PAA Natural Gas Storage, L.P. (NYSE:PNG)
Analyst and Investor Day Call
May 30, 2013 12:30 PM ET
Roy Lamoreaux - Director, IR.
Greg Armstrong - Chairman and CEO
Harry Pefanis - President and COO
Mark Gorman - EVP Operations and Business Development
Dave Duckett - President, PMC
Dean Liollio - President, PNG
Al Swanson - EVP and CFO
If you want to go ahead and take your seat, we’ll get started. Welcome to Plains All American Pipeline and PAA Natural Gas Storage 2013 Analyst Meeting. My name is Roy Lamoreaux, Director of Investor Relations. We’ve got a strong showing today – meeting. -- had RFPPs well north of 150 and we’ll see what the final turnout is but clearly that breaks the record attendants that we’ve had in the past.
A few housekeeping items; first, we will be utilizing some forward-looking statements and non-GAAP financial measures in the presentation today. I encourage you to visit our SEC filings for a list of factors that could cause our results to vary from our expectations. Also, in the presentation package that you have today, you’ll in addition to the agenda, investor contact information, participant bios in the presentation, you’ll have a non-GAAP reconciliations in the appendix. We also, although we’ve scheduled 4 hours to 4.5 hours to be here together today, there was more material than we could possibly cover and so some of the blend over into the appendix as well. So, include that for reference.
This meeting is being webcast live. As a result, during the Q&A session, if you have a question, just raise your hand and we’ll bring you the mic and please ask your question from the microphone.
It’s been a very active and productive 12 months since we’ve last met in May of 2012 and each quarter we exceeded guidance. We invested nearly $2 billion of growth capital expanding our 2012 capital program about 20% and expanding our 2013 growth capital program, almost doubling it from our midpoint last year. In total, we’ve added over $3 billion of organic investments to our project portfolio which now totals approximately 7 billion. We initiated and closed about $600 million of acquisitions including a large rail transaction as well as crude oil gathering assets.
We also have completed the operational integrations at BP acquisition, it’s the $1.7 billion acquisition that we closed just before our last Analysts Meeting and during Dave Duckett’s presentation you’ll get some additional insight into the opportunities that those assets are generating, I’m very excited about that. We’ve also continued to timely fund and pre-fund our capital investments and improved PAA’s already strong capital structure and credit metrics. And in conclusion we delivered 10% distribution growth, while generating coverage of approximately 135% and realizing total unit holder returns of over 50%. This year we’re targeting 9% to 10% distribution growth year-over-year.
First, the agenda. After my remarks, we’ll hear from our Chairman and CEO, Greg Armstrong who will discuss the crude oil market environment in North America and the opportunities it’s providing in the midstream sector. We’ll also hear then from Harry Pefanis who will discuss our assets and our position model are positioned to benefit from those strengths. And Mark Gorman and Dave Duckett will discuss how our business model, we apply that business model in both the United States and in Canada on the crude and NGL sides. Then Dean Liollio will discuss PNG’s positioning and outlook. Al Swanson will provide an overview of our financial growth strategy as well as our financial positioning and then Greg will close it out.
A quick review of our ownership structure. We have a privately held general partner, Occidental Petroleum, Kayne Anderson, EMG, management and few others hold the interest and very supportive of PAA’s growth over the years. Plains All American Pipeline is the general partner and majority interest holder in PAA Natural Gas Storage which is also a publicly traded entity ticker symbol PNG and Dean will discuss that during his presentation.
During the presentation today, we’re going to talk a lot about our business model and I thought it might be instructive to go back in time and for those of you that might be new to the story, just review a little bit of our history I won’t -- on the tip of high points in my comments but we kind of break up our history in the three time periods, the formative period in the late 80s or early 90s where we began as a marketing subsidiary of a publicly traded EMP company. Then we shifted our focus from natural gas marketing into crude in early 90s to build the Cushing storage facility, original 2 million barrels of storage capacity continued to expand into gathering assets in West Texas may be all American acquisition and IPOed, actually 15 years ago this year in 1998.
Then the next period we consider kind of refinement period. We continue to make acquisition, made an expansion double the size of our Cushing facility, made an announcement that we’d expand into Canada and then expanded into Canada. During that kind of execution and expansion period which we’d say we’re squarely in now, we’ve invested about $14 billion in acquisitions on organic growth projects, consummating integrating some significant acquisitions that have propelled us forward over the years. We’ve also expanded some of our key facilities and I would note that Cushing today, from its original 2 million barrels of storage capacity, by the end of this year it will be about 10 times its original size, about 20 million barrels. So this business model has really been a driver of our growth and part of the, a big part of the meeting today is to try to give you insight into the way that we think about the business, the way that we’re thinking about the markets and to give you a construct for how we’re investing capital in these conditions. As a result, I wanted to review just a little bit of how we describe our business model.
First is to understand the markets. We’re making very long-term investments in hard assets that will be in service for decades. As a result, we want to make sure that we have the right assets in the right places and so it’s critical for us to understand the market for the most supply and demand drivers, the volatility, the seasonality, cyclicality, the performance in various market conditions and so you’ll see us spend a lot of time as the management team focused on these, on the markets and trying to understand the markets as best as we can.
We’re really most interested in what’s the right answer versus what we really think. We’d rather have the right answer and an individual member of the team be wrong because in the end that’s what our investment decision will be based on.
And then clearly, we’re going to build or acquire the assets that are needed to meet those market needs. And I think one element of our business model that we think differentiates us as the ability to really optimize those assets and we do that through insurance, we have the proper connectivity in a very proactive way and you’ll see that in the presentations today the way that we’ve – even assets that you would think are just dumb assets, that are – that would just be receiving volume. We’ve been very proactive without attracting volumes from those systems through third-party connectivity. We’ve also engaged in commercial activities that drives additional volume to our systems and Harry will talk about that during his presentation.
And because we’re engaged in that optimization activity, then it gives us opportunity to participate in upside opportunities during all the markets or market disruptions. In the end, we think that our business model gives us a significant amount of influence over our own destiny and we think it’s a differentiating factor for the company. This I think the proof is in the pudding with regard to results. We’ve delivered 11 consecutive years to deliver results in line with guidance, about 45 consecutive quarters and that’s during a period of time where you’ve seen significant changes in petroleum consumption, production as well as imports and exports of products as well as the more temporal issues regarding crude oil prices, structure, and differentials in various grades. So we think that our business model has been proven through a variety of cycles that were well suited for the current environment.
We’ve also been very consistent in holding investor meetings. This is the seventh consecutive annual investor meeting that we’ve had. We’ve had a couple but prior to that time. And rather than go back and try to part re-plough that ground that we’ve done with you in the past, we’ve figured that we’ve just kind of highlights some of the key takeaway points that we’ve had from previous meetings, just kind of accept these as proven points and then build upon this in today’s presentation. I would call your attention to the last bullet there. We’ve been discussing the business model and the durability of the cash flow relating to our asset base for quite some time.
The focus of today’s presentation, the theme is PAA’s strong fundamentals to opportunities and execution. Our first takeaway point relates to our expectation that we’re going to see significant crude oil production growth in North America and that regional volumetric and quality and balances will generate volatility and complicate logistics. Any time you hear complicate that that provides opportunity for us. PAA is well positioned for these market conditions. We are a top provider of flexible midstream solutions in substantially all major North American resource plays end market hub demand locations. Our proven business model is giving us an opportunity to make long-term investments and capture upside opportunities that translates into a significant portfolio of organic growth. Both are very well positioned to finance our growth and maintain strong credit profile.
And in conclusion, we think that all this provides significant distribution growth visibility driven by strong fundamentals, the investments that we have made, that we’re making currently and that we have in the future. So once again thank you for being here and I’ll turn the time over to Greg.
Wow, good afternoon and thanks for the wonderful turnout today. Before I get started, I just want to acknowledge we’ve got some of our directors are here with us today. As Roy mentioned, we’ve got a very supportive Board and group of GP owners. From Occidental Petroleum today we have Vicky Sutil who is with us, from EMG John Rayman, both of which are significant owners and the general partner and then we also have Chris Temple, he is one of our Independent Directors at PAA. And then for PNG we also have Art Smith, he is one of our outside directors and so they’ll be here during the session and also through the cocktail session for a discussion.
My job today for the part of the presentation is really to set the context if you will or the environment that we believe that we will be facing over the next several years. Cleary, PAA as Roy showed has had significant growth and financial – outstanding financial performance for the last several years. We believe that conditions are such that that will continue for many more years as I want to take you through that. As a midstream company primarily focused in crude oil, I think it’s notable that if you could think anywhere in the world that you wanted to be, with respect to crude oil, midstream opportunities, it would be the United States and Canada. And we view those really has one market with some regulatory complications unfortunately but really we view as the upper North America as one market.
What you see on the upper left hand side of this chart is that the top 10 oil producers in the world and you can see that the United States is the third largest and Canada is the fifth largest. And if you subscribe to the theory that it is really one market, if you had those two together, you can see that the United States and Canada are actually the largest single oil producing area in the world ahead of Russia and Saudi Arabia. More importantly though for the midstream business that we’re in, as you look to the chart to the upper right, then what you see is that over the last four years, the United States has far and away been the largest, provided the largest growth in oil production, Canada at number two, and if you add the U.S. and Canada together, it’s 2.9 million barrels and that is superior to or exceeds, if you add the other eight largest producing countries in the world together. So again, the takeaway from this slide is that the United States is – just give me the United States and Canada is where you would want to be.
At the bottom in the slide, it simply shows the trajectory of the growth that we’ve experienced over the last four years, you can see it’s steady if not escalating growth and clearly part of the discussion today we’ll talk about what we think is continued growth as Roy mentioned. The – I knew that though I want to just spend a minute to talk about the demand side of the equation because clearly, in order to grow production you need to make sure that you have a market that you can sell it into.
What you see here is that the United States and Canada have had a fall off in demand, partly due to the economic recession that hit us in 2008 and 2009 but it’s stabilized roughly at around 21 million barrels a day of consumption between the U.S. and Canada. And our outlook at least is that it’s probably going to stay stable in that range with population growth being offset by continued conservation, fuel efficiency et cetera and so we’re looking for basically a backdrop of roughly 21 million barrels a day plus or minus, 0.5 million barrels a day.
What you also see on this chart in the bracket is that about 70% of that consumption is provided by indigenous production within the U.S. and Canada. So, if we look at petroleum balances and the sources of it, what we’re going to do, I’ve added to consumption in the U.S. and Canada, also the amount of net exports because we are a net exporter of refined products. Now, that brings our total up to about 22 million barrels. And of that 22 barrels, about 15.5 million or 70% is provided by U.S. crude oil production, Canadian crude oil production, production of NGLs in U.S. and Canada and then also ethanol. And what that means is we’re importing 6.5 million barrels a day into U.S. and Canada by waterborne sources and of course now we have some context against which what will rising production if demand’s going to hold steady, where are you going to take the rising production to. And what we’ll be doing is displacing some of those waterborne imports so we’re roughly about 6.5 million barrels a day of opportunity.
With respect to production, our analysis and we put together a very extensive analysis internally at PAA, a combination of our own internal analysis as well as some outside third-party studies. We also used producer input, our customers telling us what they are going to do and then anecdotal information and we’ve done this in most of the major or all the major resource area of shale or resource areas I’ll use interchangeably today. The big three, obviously being in the U.S., Permian, Eagle Ford and the Williston Basin. In the Williston and the Eagle Ford we’ve actually done a county-by-county, well-by-well analysis. In the Permian which is a little more complex and – we’ve used combination of our analysis plus third-parties and we’ve taken that same approach in other areas. But based on that, we’re expecting production over the next four years, last four years it was up 1.9 million barrels a day, 2.9 excuse me and what we’re looking for going forward is it’s going to be up 3.4 million barrels a day over the next four years. And that’s indexed at that we’re basing that off of an exit rate in 2012 of 10.5 million barrels a day.
The production increases is primarily or at least our method of forecasting is based on maintaining a constant rig count and well results that are in line with historical well profiles. We think that’s realistic if not conservative in the sense that we think while there is certainly some risk that well counts go down or rig counts go down, we think well ahead it will be offset by increased drilling efficiencies and completion efficiencies so that we think we’ll still be in the right neighborhood of around 3.4 million barrels a day of production with a little bit of a caveat that that 3.4 million barrels a day is available to displace about half of what we import, 6.5 million barrels a day assuming these are still quality related issues. And one of the things you’re going to hear today is that our quality related issues and they will have an impact especially on certain regions on the weight and velocity of the production growth in each of those areas. So from a standpoint of just looking back and saying is there really enough resources to support that type of production growth, this map is intended to show you basically what total shale oil or resource oil in place, it’s roughly about 1.2 trillion barrels.
The forecasts that this is information from – is that the assumed recovery rate will be about 7.5% and we’ve already recovered about 1.4%. So, we really have significant amount of resources there in place and it’s been technologically proven to be able to be accessible through a combination of horizontal drilling and hydraulic fracturing. Economics will play a role in it. And with respect to economics net wellhead price matters and it matters a lot. Transportation and quality differentials clearly are going to be an influence on that net wellhead price. What we’ve done on this chart right here just is an illustration only is showing you in the Bakken or the Williston area what part of our analysis shows and so we’ve gone in these areas and categorized each of these wells into tiers, tier 1 through tier 4 in the Three Forks and somewhere in the Bakken formation.
And then after the right, we’ve shown you which on these well profiles, which well we think will actually be economic at what prices. Certainly the continuation of current price range we would expect production to grow from roughly about 850,000 barrels a day at year-end 2012 through just 1.4 million barrels a day in 2016. And you can see the shades of red and the greens where we think the economic profiles are. So clearly, if oil prices do decrease at the wellhead, it’s going to affect the rate of drilling in these areas but it becomes a self-correcting issue because its production falls and demand stays flat, we end up with prices coming back. So we think this sets the stage for what is – has been a very volatile period in crude oil prices index and differentials and what we think will continue to be.
So we’ve got resources that are technologically and economically validated. We’ve got very good diversification of those production sources. Our 3.4 million barrels today are coming from primarily seven areas, Canada is the largest as one group. We’ve got Gulf of Mexico, Permian, Eagle Ford, and the Williston or the Bakken area, Mid-Continent as well as in other parts of the Rockies. And so we feel very good about those inputs into our model. What does cost in complication, if you look at the composition of the 3.4 million barrels a day of increased production that we’re expecting over the next four years, about 2.4 million barrels a day of that is actually going to be condensate and light sweet crude oil production. And we think that particular quality of crude is going to overwhelm the market for the particular type of crude. So, volumetrically, we have 6.5 million barrels a day to displace of waterborne imports but qualitatively, we’re going to have to wrestle with some issues as an industry. And as Roy mentioned earlier, complications kind of make us smile because we get paid to solve those complications.
So when you look at where are these imports of 6.5 million barrels a day coming from, you can see it’s kind of in the West Coast, the Gulf Coast, the East Coast of the U.S. and then upper East Coasts of Canada. And find the largest import area in the U.S. or in both countries are the Gulf of Mexico, 4.4 million barrels a day but we’re already down to only about 5% of those imports are a condensate or light sweet. And when you look at in the U.S., and this is just U.S. only, you can see what’s happened historically with respect to imports, aggregate volumes have been coming down. If you look at the shades on these stag bars, the very bottom represents the light sweet and condensate imports and they’ve come down dramatically. And by the end of 2014, we expect, basically to have eliminate all but about 5% of light sweet imports. That’s a little more complicated than – on a regional basis you may have way too much in one area, you still need a light sweet crude in another area. So to put in perspective, how this translates into our ability to process light sweet crude, we’re using 2012 as level of processing our refinery inputs as a proxy and you can see that the total light sweet and condensate inputs into refineries and 2012 was just under 6 million barrels a day.
The bulk of that provided by indigenous production in the U.S. and Canada and then the balance of it about 1.4 million barrels a day of imports into the U.S. and Canada from other countries. As we look forward though, we’re expecting that indigenous production increased 65% of the light sweet category and you can see if in fact 2012 represents the maximum capacity of refineries to use light sweet and condensate crude, that the sheer volume of light sweet crude and production that we forecast in our analysis will exceed that capabilities, again creating some complications.
Why does it create complications? Well about eight years ago, many refiners started spending on investment side, the billions upon billions of dollars to improve their ability to run heavy sour crude. They spent that money basically on adding or expanding their cokers, the hydrocrackers and other equipment within those refinery compounds to be able to process the heavy sour crude. About four years into that investment cycle, we started seeing life in domestic production and we started seeing over the last four years, an increase in domestic production, 2 million barrels of which was light sweet which has been reversing a decade long trend. So you’ve really got two directions coming together in conflict. And while the refiners can’t – light sweet crude in certain of these processing units, it’s done at tremendous inefficiencies which can be compensated with by more blending of lighter product with some heavier product or with actually running the light sweet product and just living with the inefficiencies but economically you’re going to have to be able to buy that crude at a discount, to be able to make it worthwhile to run those refineries.
So then let’s look a little bit at the implied heavy processing capabilities in the U.S. and Canada and here you can see in 2012, heavy and sour refining inputs – inputs into refining, excuse me, just allotted about 11 million barrels a day, 5.1 million barrels a day of that which was waterborne imports. Our forecast for increases in heavy sour crude is not as robust as it is for light sweet. It’s only about 1 million barrels a day but up 25% and you can see what’s happening is our ability to import remaining volumes, it’s shrinking down to about 4.1 million barrels a day of heavy and sour product which we believe will compete with heavy sour imports against light sweet production from the U.S. and Canada.
Put that into a tab that you formatted just simply says we’re out of balance. We’ve got plenty of room to absorb increases in heavy oil production and not as much in light. In fact, it will have about a million barrels of day of excess. It looked simple in a chart. The reality is on a regional basis, it’s much more complicated. It may be a net million barrels excess but we may find out that 1.5 million of that excess is one place and you need 1.5 million barrels transported to another part of the U.S. So because we have some restrictions on both – issues as well as with respect to exporting light sweet crude. In general, it’s going to create more complications.
So far, all of the differentials that you’ve seen, erratic behavior in with the last couple of years have been volumetric related that simply more volumes coming out of these areas than there was pipeline or other means of transportation to get it to market. Top two charts here show you basically an example of that. What we think going forward is we’re going to continue to have some volumetric disruptions but as pipelines get built, they get crude from one market to the next. You’ll see those volumetric differentials degrade down to where it’s basically the transportation costs but what we’re going to see is transitioning into a much more erratic and highly stressed situation of qualities of crude in the wrong places. And in certain areas, we think what this is going to lead to is that light crudes may well be priced at discounts to having crude which is exactly absent of what you would have thought historically.
So what are the potential solutions to quality imbalances? It’s going to require some activities from both the upstream and downstream as well as the midstream. Certainly, we can see and we will see increased usage of condensate by petrochemical companies but many of those won’t be up and running for a couple of years. Refiners can make modifications to the refiners to accommodate more like sweet crude just like they did to accommodate more heavy sour crude but it does take capital and in some cases, we think there are going to be – want to be property incentivized with discounts or arrangements, long-term supply arrangements to make sure that they’re going to be able to capture that discount if they make the investment of capital.
Certainly there is some potential for release from the president with respect to crude oil exports. Politically, that’s generally not the best solution because of gas, price of gasoline, the pump goes up after they allow that. It certainly doesn’t do well for being re-elected. And then, clearly, as prices affect net wellhead or the differentials affect net wellhead price, it can cause either delays in drilling which will solve the problem or in shut-ins at extreme.
Midstream solutions, you’re going to see long haul shipments of condensate to Canada as diluents. In fact, these long haul shipments probably to the Upper East Coast to displace imports of Brent like crude. Rail barge – new pipelines whatever it takes, we’ll do to get the crude from where it’s at to where it needs to be. And then you’ll see some installation and we’re already hearing it, condensate splitters. You can’t export crude but you can export product that’s been processed and right now, the periods if you split condensate, you can export some of the products.
Our belief is it’s going to take in all of the above. No one solution is going to work. And so you’re going to see a lot of these, all happening at one time and in many cases, there is a tendency especially on a regional basis to over solve the problem which creates another series of issues.
One thing that I want to touch on before I turn it to – summarize my section and turn it over to Harry is we have experienced what I would call very favorable conditions over the last several years for U.S. refineries to compete in the world market. Demand in the U.S. has been relatively down about 10%, in holding at that level. At the same time we’ve had refinery inputs in the U.S. that have been basically holding relatively steady. And the way they’ve been able to do that is by decreasing the amount of refined product imports and actually significantly increase the amount of refined product exports.
We’ve actually decreased refined product imports from the 2005 to 2007 period by about 1.3 million barrels a day and we’ve increased our exports from 1 million barrels a day to 3 million barrels a day. So a net swing in there of about 3.3. You could see on this chart right here. So we’re now actually providing world’s product because we’re able to buy crude at a cheap price relative to world index prices such as Brent and because our cost of power in these refineries through natural gas in U.S. is selling at a much cheaper level than it is to European refiners that are reliant on LNG based gas supplies to fuel their refineries. So overall, it’s actually helping the refiners to make increasing margin but it’s actually indirectly helping the producers in the U.S. have a market for their crude. If that differential was to go away, we’d actually see a situation where the prices would actually have to collapse. So it’s important that we keep our eye on that development to make sure that in fact we are seeing incentives to continue to export refined products.
So, to recap our position in terms of long-term, we expect petroleum demand to remain relatively stable, plus or minus, about 0.5 million barrels a day. We think the resource plays will provide significant increase in production. We’re estimating 3.4 million barrels a day. It’s dominated by light sweet crude about 2.4 million barrels of the 3.4. The production curve will be erratic because you’re going to see differentials widen and in some cases, may affect wellhead price significantly enough to slow down drilling to become self-correcting overtime. In addition, we’re going to see midstream solutions, start to be staged in but it’s a rule in general, as an industry we never quite get it quite right where we timed our addition of the pipeline takeaway capacity exactly to coincide with the production increases.
We think as a result, you’re going to seek significant volatility not only with respect to volumetric imbalances but because again of quality imbalances. And then we believe overall, the conditions will be such that it will continue to encourage and enable the refiners to process enough crude to be able to export to the world markets. And ultimately we think solving these problems going to require all of the above type approach.
What does that mean for the midstream opportunities? We think demand for the incremental infrastructure alternatives will continue. We think emphasis will be placed on and there is clear preference for those that provide flexibility to access multiple markets. Having a pipeline from one point, A to point B, at point B is not the best market, is really not a preferred alternative. You know it’s easier to move crude by pipeline. In many cases, it’s actually more economic to move it by rail or truck, excuse me, to an alternative market. And then, lastly, we think midstream companies that correctly anticipate these market dynamics and possess flexible assets will have significant profit in growth opportunities.
So with that, I’m going to turn it over to Harry to take you through – for the assessment of our positioning in that market.
Thanks Greg. Let me start off by -- starting with Greg mentioned earlier that we think we can see volumes increase by about 3.4 million barrels a day over the next several years. So I want to start with this map just to show you where we think the volume growth is going to occur. And we’ve also laid on this map, our asset presence so to be able to see that we have pretty significant asset presence in all the major onshore growth areas in North America. I’m going to spend some time going over our asset positions in some of these major areas and then a little later, Mark Gorman and Dave Duckett will talk a little bit more about our current activities in some of these areas.
So let me start with the Permian Basin. It’s an area that we have our largest footprint in. We have over 3,500 miles of pipeline in the Permian Basin. We have – above 1.1 million barrels a day and we gathered wellhead that was first purchased, about 325,000 barrels a day. And then we also have a tankage of about 8 million barrels in the Permian Basin. Now this is tankage that’s in excess of the operating – of our pipeline assets. So it’s available for our commercial activities that support our commercial activities. This is also an areas where we expect volumes to increase by about 500,000 barrels a day over the next several years. So, I think you can see from this map we have a pretty vast system, pretty vast gathering system but in addition, we have – this is something that provides a lot of flexibility to access different markets.
Moving over to the Eagle Ford, it’s relatively new area for us but as you can see from the graph on the slide, in 2009 volumes in the Eagle Ford were only 30,000 barrels a day. Volume growth has been tremendous. It’s over 800,000 barrels a day. Today, we think volumes can get to 1.6 million barrels a day. Now, this is an area where our footprint has grown pretty rapidly as well. It’s been through a combination of acquisitions and development of internally generated projects. Our throughput capacity on our main line system which is the joint venture pipeline system we have with enterprise, and it’s in radius of about 350,000 barrels a day. And we have a pretty meaningful gathering presence behind our Gardendale terminal. We have about 400,000 barrels a day of gathering capacity on the system. That’s the pipelines that are in blue and purple.
Not only do we have pretty significant gathering presence but again we’ve got pretty flexible system to market the products. We have not only can we deliver crude to market by pipeline, we can also go via train at our terminal as Gardendale and hope we can also put crude on the water on vessels at Corpus Christi terminal.
In the Mid-Continent area, we have again a pretty significant presence. We have almost 2,000 miles of pipeline in the Mid-Continent area. Our pipelines move about 250,000 barrels a day and we gather at the wellhead about 100,000 barrels a day. We also have about 23 million barrels of storage in the mid-continent area. Again, that’s capacity over and above the operating requirements to our pipeline. Most of the storage gears at our terminal in Cushing. We think volumes in this area can increase by about 200,000 barrels a day over the next few years. We think most of that volume is going to come from the Mississippian line and then some of the resource plays in Western Oklahoma Scoop, Granite Wash, Cleveland Sands and when you got a pipeline infrastructure here, we think we’re well positioned to participate in the growth opportunities in Western Oklahoma.
Move to the Rocky Mountain area; again, pretty significant presence. Our footprint here includes almost 3800 miles of pipelines. Our pipelines move about 400,000 barrels a day of crude and we’re first purchaser of 150,000 barrels a day. Here we see, as you would expect, most of the growth become in the Bakken portion of the Williston Basin and then when you go to the Niobrara, we think kind of in the most of its going to be in that Weld County, Colorado area. We have a significant presence in both areas, not only do we have pipeline capacity but we also have rail loading capacity. We have two existing rail terminals in the Bakken. We have an existing rail terminal at the Niobrara and one under construction at fourth rail loading facility set to be in service, little later this year, third quarter this year. So in total, we think this area can add about 700,000 to 80,000 barrels a day of volume.
And then, lastly I am going to touch on our Canadian operations. It was noticed first off that we do not have any long haul pipeline systems but we do have a pretty meaningful footprint in the feeder pipelines. Our pipelines, feed the main line systems. We have about 3,100 miles of pipe in Canada, in Western Canada. We have 430,000 barrels a day of crude on our pipelines and here, our commercial presence is really in the form of the single ship around our feeder pipeline systems. Now not only do we have pretty meaningful presence in crude oil, we also have a pretty significant footprint in the NGL segment as a result of the, reach an acquisition of PP’s and GL assets. We have meaningful footprint in supply area of Western Canada and then also in the market areas of Eastern Canada. Dave will touch on this a little later in his presentation but in total, we’ve got 200 miles of NGL pipelines. We have about 230,000 barrels a day of fractionation capacity and we have about 22 million barrels of storage capacity.
Let me point out that the storage capacity, it’s about 1.5 in Canada from the BP acquisition. The other half is in U.S. It was storage assets we had prior to the acquisition of PP assets. I touched on our pipeline assets but we also have pretty significant presence in our terminals and all the crude oil market hubs in North America. We have over 115 million barrels of liquor storage capacity at hubs like Cushing, St. James, Midland, Patoka in the U.S. and then in Edmonton and Kerrobert, Canada.
So Roy touched earlier on our business model. And as you can imagine the assets didn’t fell overnight and they’re not a random accumulation of assets. We’ve basically applied our business model to each of these areas. And like Roy said, we started off trying to understand the fundamentals, but we think the crude flows are going to be, but our key assets that we need to own to be in this area, what assets need to be developed so we formulate our views, tried to – build the assets and want to support those assets with a commercial presence. We think it’s important to have the commercial presence. Commercial presence actually brings fee-based business to our pipeline assets. And then we wanted to either acquire or develop bolt on opportunities. And as you saw, as I went through our interesting presence, we tried to maintain as much flexibility both from the supply source and a market availability around our assets. And then, you want to incentivize performance and reward performance and we think that’s one of the keys to our success as well.
I want to go through some of the areas and talk about how we developed our position, the interplay between our key assets and our commercial presence. It’s a busy slide. I’m not going to touch on all – there are few highlights here but let me start with Mid-Continent. We started with our Cushing terminal that was the first midstream asset that we actually add to – 1993. And to be honest with you, we wanted to lease it all to third-parties, it just sort of be a fee for service business. But that’s hard to do. And when you’re developing the grass roots project so we’ve developed the commercial strategies in-house, built the terminal and it really started our, initiated our presence in the midstream segment. So after that, we were able to not only expand the terminal but acquire bolt on and develop bolt on opportunities mainly pipes, spring and crude to our terminal or taking crude from our terminal to create a lot of liquidity and really the opportunity for growth.
In the Permian Basin, we had an opportunity in 1999 to acquire Scurlock Permian. It’s basically a crude oil gather. It was a supply for Marathon and at that point in time the crude oil business was pretty cyclical, volatile. It was very profitable. The market was backward aided. It was now, very profitable, could even generate losses in a – market. And let me just say that we’ve totally changed that business. When you look at our crude oil gathering business, right now it’s basically a fee for service business. We’ve taken out all the volatility. I’ll talk a little bit about that later.
But because of that volatility we want to have an asset presence in the Permian as well. And Chevron had its pipeline assets up for sale. What’s excess gathering system not only did it provide the backbone for our gathering presence, it also has significant amount of storage so that enable us to have sort of a counter-cyclical balance between the storage assets and the volatility of the crude oil gathering business. And then, couple of years after that 2002, we were able to acquire the basin pipeline system. And so, off the presence of the basin pipeline system the gathering presence in West Texas and the commercial presence we have, we were able to expand quite significantly through acquisitions and development of expansion and extension opportunities.
In Western Canada, we had a similar situation – it’s kind of reversed. We have the opportunity to buy Murphy’s pipeline systems in 2002 but really felt like we needed a commercial presence. Met Dave Duckett and his team in 2002. They were operated a lot like we did in the Permian Basin. They had very commercial – to their business model. They just were a little light on assets and the MLP structure had excess of the capital so we were able to put together. Dave’s team currently runs PMC and they’ve done a tremendous job in growing our footprint in Western Canada. So, basically the same story here in the Gulf Coast, the Rockies and the Eagle Ford, just different assets ad different commercial opportunities. I’m not going to go through all of these but you can see how we’ve been able to not only establish international presence but create a lot of bolt-on opportunities in each of these areas.
Not only has our commercial presence been key to initially setting up our presence in an area, but it’s also support a lot of organic growth. I’m going to touch on a couple of opportunities to give an example of how supported growth in our facilities segment and then I’ll talk about our transportation segment as well. I’ll start with our three terminals; Cushing, St. James and Patoka, all three locations. We started Grassroots operations. No third-party contracts. These were all developed based on – our commercial strategies, we started off with footprint in each one of these areas between 2 million barrels and 3 million barrels as we developed the storage facility started implementing our strategies, typical refiners but others in the industry saw the benefit of having the tankage in these areas and want the least tankage. So what we would do is we would take the tankage away from our commercial guys, enter in to long-term contracts with refiners or producers and then build new tanks for our commercial guys and that cycle repeats itself a couple of times in all these areas. And as a result, we’ve significantly expanded in each one of these areas. You can see in Cushing and Patoka for example, we currently have 19 million barrels of Cushing, 6 million barrels in Patoka in both locations, 90% of its leased to third parties and only 20% or only 10% is supported by our commercial activities.
Similar process with PAA taking 20 Bcf of storage at PNG’s Pine Prairie facility that enables PNG to pursue some very low cost expansion opportunities at Pine Prairie and we’ll use the same type of philosophy with the BP acquisition assets. Currently, BP operated at totally commercial operation, will phase into bringing -- expansion opportunities bring third-parties in that – so our combination of fee based earnings from those assets as well as the commercial presence.
On the pipeline side, I want to give couple of examples how our commercial activity supported the development of some of our pipeline projects. I’ll start with the Rainbow II project. That’s an asset that will be in sort of later this year. We saw an opportunity to take diluents condensate to some of the heavy oil production in Northern Alberta so we booked a pipeline to do that. We think by the time the pipeline gets in service or shortly after it gets in service, pretty confident that we’ll have a fairly substantial amount of that capacity committed to third parties. In the West Texas, we saw lot of the drilling activity going all behind our gathering systems. We initially started increase, expanding and extending our gathering systems. Not only that, we saw opportunities to have low cost expansions of basin pipeline systems and Mesa pipeline system. We increased both those by about 50,000 barrels a day without any commitments and overtime, we’ve got commitments for both, our gathering expansion and extensions and committed capacity on our pipeline as well.
So in the Mid-Continent, what happened to Mid-Continent was he had a congestion in Cushing, he had a bottleneck, so you had – differential between the price of crude and Cushing and the price of crude in the Gulf Coast with a couple of pipelines were feeding Cushing, reversed them, we’re able to take through to higher value markets and I think we were able to get refiners to commit for the capacities. We took our commercial SNL revenues and converted it into long-term fee-based revenues on both these pipeline systems.
And then – I’m sorry on the on the Medford Pipeline System, it was an NGL system, moved a couple thousand barrels a day seasonally from Medford to Tulsa saw opportunity for the crude service, secured commitments not only for that pipeline but for the development of our Mississippi line pipeline system.
So talked a lot about how our commercial activity supported our fee-based business. But like I said earlier, we really turned the gathering business into a fee based business. It’s no longer cyclical. Our – both our supply and our markets, our tied to indexes that move daily and we really converted it to a business where we’re getting paid to five transportation service, accumulate crude oil, handle the – management and take crude from the wellhead to the market. But that also puts us in a position. We have opportunities for some very low risk upside opportunities. So what I mean by low risk upside opportunities, I’ll give you a couple of examples.
The drivers of those events are typically supply or demand imbalance that exists, say for instance, there is a perception in West Texas this year that you don’t have enough pipeline capacity and move crude out of West Texas. So that incremental barrels moves truck transportation, differential blows out to $10, $12 for the entire basin so that incremental barrels driving the whole basin. If you’re a historical shipper on the pipelines, you’re the guy that’s got pipeline capacity out and you’re able to move crude that was typically at a $0.50 or $0.60 differential to a higher valued market. The transportation costs are the same on the pipeline that’s – of $10 million margins that of the $0.50 margin on that movement.
Another driver of some of these opportunities as a refinery outage is unplanned obviously, but some of these unplanned refinery outages cost the – to store crude and tankage and it’s really localized – market and again, it’s that incremental barrel that’s driving the value for all the barrels in that area. So that gives you idea of how we drive some o four upside opportunities. We’ve had outside opportunities over the last few years and made a fair amount of money in these market conditions but we haven’t distributed those excess earnings. What we’ve done is we’ve taken those excess earnings and re-deployed it. We put that money into developing our organic growth opportunities. So we’ve converted it from short-term opportunistic earnings to long-term fee-based earnings.
So, we’re in an environment as everyone knows, sort of at the – with the wind at our back. It’s been a great time to be in the midstream business, upstream business as well. Lots of development opportunities exist. Over the last few years, we’ve invested over $7 billion and that’s been a combination of asset acquisitions as well as internally developed projects but about two-thirds acquisitions, one-third development project and so we’ve invested a significant amount of capital into fee-based opportunities. And really, we kind of had a step change over the last few years. As you can see from this graph, from ’06 to ’11 we were in that $400 million to $500 million range capital opportunities, there were mainly terminals but now with all these resource plays, we’re seeing opportunities to expand and extend pipeline systems. So it’s really double the opportunities said. Our portfolio now was weighted between – equally weighted between transportation assets as well as facilities.
And it’s a – but one of the things that it’s done is terminals that can generally be completed in say 6 months to 12 months of pipelines that longer may be 18 months. So there’s little longer time left between the time that you’ve expand the capital to a time you start driving EBITDA growth. So, we spent a lot of capital. We’re just starting to see the EBITDA associated with that capital.
Looking forward, as Roy mentioned earlier, we have a substantial backlog of projects. We have about $7 billion that includes about $2 billion of projects that had been approved and include in our 2013 plan, about $5 billion worth of portfolio projects that had been identified. We won’t develop all of them but what happened is as you develop these projects, they expand other development opportunity. So, it includes that very full set of opportunities looking forward and we typically target on these type of development opportunities sort of mid-teens types of returns.
And let me just touch on acquisitions a little bit. They’re hard to talk about because if you’re looking at one, generally subject of CA so you can’t really discuss much about. But it’s an active market. There are a lot out there that’s in the market but what we’re seeing it’s as you can imagine with the full cost of capital, it’s very competitive, got other parties that are trying to enter into this space. Midstream companies that want to gas business to refine products business at will and they pay premium to that much of foothold in the crude oil segment, the crude oil space. So, we’re going to be patient, we’re going to be disciplined, but we do think there are opportunities out there for us. You can see we’ve been able to make an acquisition every year. I’m not saying that’s going to happen in the future but hitting the Gulf over five years plan, we still think it will be able to spend $700 to $800 million a year in acquisitions and you can see over the last few years, we’ve got like 900 million. So it’s a little lumpy but overtime we think we will continue to have acquisition opportunities.
So, let me just close with couple of takeaway points. First, able to demonstrate that we have meaningful footprint and we’re probably one of the major players in all of, in each of the major resource development plays. We think we have proved a model that’s helped us get to the position that we’re at today and we’ll lead to investment opportunities in the future and we have a strong visibility for continued fee-based growth in our business. That includes not only our portfolio of capital projects but we’ll be active in the acquisition arena as well.
So, with that, I think we’re going to open it for a Q&A here.
Greg come up and parker with me on this.
Give any questions that’s --.
We’ve got questions right then. We have microphone back here.
Hi. I actually have a question for each of you. Harry, just if you could – going back to your comment, excuse me, on Rainbow II that you anticipate contracting some of this out for third-parties, can you talk about the commercialization now of the pipeline and how it’s been used. It all internal?
No, the pipeline is being commissioned in June or probably start of August 1st. Third quarter it will be in service. So, we think, yes, what we did there is we had enough demand to start the pipeline with trucks are moving, condensate and ore so we’re just taken offshore pipeline and transportation savings which drove the pipeline to start, we drove our desire to have the pipeline to start with. We are in discussion with a couple of parties and we are confident that we’ll have third party business on that pipeline.
Great. And Greg, we include, regarding your comments about, they will be quality, volatility going forward and we’ll actually see light crudes at a discount to heavies’ overtime. Do you think this will allow for the continuation of the nice returns you’ve been getting from the let’s that one call trading but the split games that you guys have been playing and the marketing business that you’ve been operating.
We do think there will be a lot of opportunities. I mean at any time there is going to be volatility and some dynamics in that market whether it’d be market structure, -- or whether it be crude oil quality or just as Harry mentioned, pipeline disruptions there are so many new projects that were coming on stream and if you take our forecast of volume growth which likely we’ve been actually running a little bit behind, that was – little bit ahead of our forecast in certain areas, especially in West Texas. What it tells you is that any of those other projects are late or have shut-ins or refiner who though that they were going to have a one-week turn around, has a three-week turn around. It disrupts the market. Anytime you have those types of situations, that’s where we have the ability to our supply and logistics group to capture those opportunities. It’s very hard for us to predict when they’re going to happen? So if you ask me we are going to put it into our next quarter’s guidance? The answer is no.
If you ask me over the next 18 months would I be extremely disappointed if we didn’t have several opportunities to have those type of events, I would be distraught if we didn’t have those opportunities. So, we feel very confident about the markets have a chance – volatility will continue if not intensify. It will just change in terms of – right now, it’s primarily volumetric. It’s soon going to be both volumetric and quality related.
I’ll just add on. I’m not sure that we’ll see $10 differentials from West Texas but if we take our asset position, it puts us in a situation, we’ll be able to capitalize on these locations.
And I think if you, when Mark Gorman gets up here, one of the things I think we’ve gone out of our way to try and do in this presentations to address kind of what’s happening in West Texas and how basin fits into that scenario. And if you kind of envision the comments that we just made about potential for other parties to have delays or disruptions, you’ll see when I am talking that we are basically the swing provider of services and all that.
Any other questions?
Yes, following up on that. Do you expect given the continuance of production growth on the crude quality issues you’ve projected in the future, that with the addition of our rail assets, how did you think the business mix from supply and logistics although continue to be in this ballpark which is above historical average?
Well, we’re going to get back Brian to predictability of it. I think over, again in 18 month period, 24 month period, I think we’re going to average above baseline, no question. I just don’t know whether it’s going to be in the second quarter or the third quarter or every quarter. So, in general, the answer is, for the reason we talk about the volatility is going to be, we’re going to have the opportunity to capture above baseline performance. We started off at the beginning of this year, kind of given you an indication what we thought supply and logistics baseline would be, and we said there is an upward bias if in fact we see market opportunities and obviously in the first quarter we saw a significant amount of market opportunities. Harry mentioned the differentials, the Midland Cush differentials blew out, several $12. So going forward we think that’s for sure, we think your comment on rail and Mark will address in his presentation, we think it shifts. I mean right now, you’re seeing actual people pulling barrels off of pipelines to put it on rail.
So for example, one of our pipelines in Rockies is probably running 65% of capacity where for the last two years, prior to June it was running at a proration. And so what that really means is the markets are changing and with the addition of these increased light sweet volumes is going to change again, all those changes result in volatility that results in opportunities. So, we think rail is going to be a significant part of that for the next several years. We’ve kind of used a five-year window of rail being very prominent and then we think it falls off a little bit at left because I do think you’ll see some pipeline solutions that will be more permanent but you’re still going to have rails, going to have to be going to the East Coast and West Coast because you’re really not going to have pipelines to be able to service those areas.
And just one more question, given the expectation of regional imbalances to grow, which of the restrictions currently in place you think could potentially be eased or it’s – or exporting crude?
Could be changed to accommodate grater product list.
Best for me to predict what Williston is going to do is pretty dangerous. I would have told you that the keystone pipeline for example should have been approved 1.5 years to 2 years ago and here we are today, still not approved. And so, I don’t think I can predict what worst is going to do. Whatever is rational they probably won’t do. So, but I do think some of the things that there are work around. So for example, while the – which requires you to go from one U.S. port to another U.S. port, it’d be a U.S. flag, U.S. staff and built vessel. There is a limited number of those but if you take some of this product from the Gulf Coast with us from Corpus Christi or from the Houston area, on the same vessel and you take it to Canada and you displace part of that 600,000 barrels a day of light sweet that they’re importing – gets that qualified. You don’t have a restriction on that. So I think there is some work arounds on there that are going to occur. I think it’s possible that it’s a same add-on. They would allow you to export light sweet if you imported an equivalent amount of heavy sour, so that they say we’re not volume disadvantaged but that requires a rational thought.
Hey, Greg. With respect to the refiner reconfiguration that you were talking about, as it relates to handling that incremental light sweet barrel that’s coming from the Eagle Ford or from the Permian, obviously recognizing that production growth out of the Eagle Ford whether or not it’s crude or condensate and the Permian, is it going to be linear with the refiner’s ability to handle all that incremental production. When do you think we hit the buoyant vault to the extent where the refiners are either unhappy with the price they’re getting for the amount of metal distillates they are producing and it actually starts changing producer economics back to the wellhead to the extent that it disconnects TI to a greater degree and possibly even starts to pressure Louisiana light sweet?
I think it’s starting now. It’s going to be a continuous process I think there and it will be vary by regional area but ultimately those differentials will have to get pushed back to the wellhead. And in fact it’s one of the things that we’ve got here as our give away if you will, we’ve got some crude oil samples and then there is a – that goes with it that shows you the variety of those crudes, the refinery distillation value for those at the intermediate stage level, ranges from, includes all way from Eagle Ford through Orienta and West Coast or what WPS is $90 to $105. So it’s a $15 differential in the qualitative output or the value of the qualitative output of those. So, on a regional basis, those are going to vary from time to time. And then we’ve also got a macro issue which is what China going to do.
As long as, because for every barrel we’re pushing out of the U.S. and we’ve got 6.5 million barrels to push out, production is only going to go up 3.4 at least in our estimate that means we’ve got plenty of cover. But the 3.4 that we’ve pushed will have to go somewhere, where does that go and I think we’re all looking to China and saying don’t drop the ball. And but as long as they can take that quality or what they take will actually impact what’s available to us to have for heavier blend because you can’t take some of the real life condensate and blend with some of the more ugly heavy sour. But if that heavy sour starts to get priced up because it’s going to China, then it’s going to change again.
So, takeaway from here is volatility, volatility, volatility PAA wins.
The other component is there are several refiners that have permit spending to expand the refineries to be able to process more light crude. So, it will be interesting to see how timely those permits will prove, so that could really be a little bit of a bottleneck too.
When you circle out the shift from volumetric imbalances to quality imbalances, how dependent are you on refineries and the release in chips that you have with refineries to take advantage of those quality imbalances. And what prevents the refineries from arbitraging those differentials themselves?
They were very dependent on refineries. They’ll take all our crude. But to prevent them from, basically just competition, right? Part of our – part of what we’ve tried to do is take crudes to the most competitive markets and try and create competition for those volumes and take them to the right locations. So, there will definitely be pressure to price the crudes relative to your refinery also in a position we are trying to price crudes relative to your opportunities as well. And so they’ll price and imported crude against potential import crudes against or run a heavier crude against the lighter crudes and try and push that back.
Yeah, I would also put, I mean one of the things the refiners want is predictability and stability of their feedstock. So, if it’s in a regional area where they actually have some gathering assets or some midstream assets, I mean they are going to try and compete as Harry said with us head to head on trying to capture those volumes because they think they can get a reliable stream. But if it’s a situation where they’ve exhausted the capabilities to those systems that are relying on the macro system, that’s where PAA really becomes is very well positioned because we handle probably 3.5 million plus barrels a day throughout our entire system and probably over 100 different grades and varieties. So we have the ability to react and come up with the right value blends as well as the quality blends so it’s least disruptive on the refiners. So, it’s a very symbiotic relationship. Clearly, they want to make more money, we want to make money and we got to make sure the producer makes or we don’t have the crude supply. So there is healthy tension there but it’s a very positive relationship. And in many cases, we take a long-term view. We don’t try to milk every transaction for the last dime, just for contrary we’re basically trying to enter into a sustainable extended relationships and we’re lead money on the table in the short-term to establish a long-term relationship in converse it will do the same thing. So, it’s not an unhealthy relationship there at all, it’s very healthy.
Can you provide some color on the SNL volumes percentage or a range more than 50%, less than 50% from the Permian versus the Bakken versus Canada? Any range on that would be useful.
Yeah probably the best response is, and I don’t have it off the top of my head but if you’ll look at each of those –
Greg, you might step up to the mic.
Excuse me. If you look at each of the maps that we have, we’ve got basically how many volumes we gather in each of those areas, and I think we’re totaled around about 1 million barrels a day.
Yeah, about 900,000 a day in the U.S. Permian 325,000 of that, the Bakken is 150,000, Oklahoma is about 100,000.
But those numbers are changing as we speak and obviously if you think about it, we’ve got 3.4 million barrels a day of projected increase. We expect to get at least our fair share of those volumes so it will vary depending on where those volumes are coming from.
And so apart from your own gathered volumes, the third-party volumes are also in the same range for SNL specifically?
I didn’t understand your question.
The supply and logistics segment, Greg, for that segment, the distribution of volumes between different areas, is it the same for your own gathered volumes versus if you take third-party volumes and how marketing spreads on that?
So the volumes that we quoted in SNL, those are all volumes that we’ve first purchased. They’re primarily on our assets, but not always on our assets. But the bulk of those gathered volumes are trucks, are our pipeline systems. We do have independent third parties that would contract for trucking service in some areas to supplement our own but the bulk of that is on our assets. So then supply and logistics only makes up a component of the transportation segment volumes. So, some of our supply and logistic volumes will go on our pipeline systems. So if you look at the Permian, we’ve got 1.1 million barrels a day of tariff based volumes. So, roughly a third of it is from volumes that we gathered, the wellhead and the rest of its third-party volumes. Did I answer your question?
Yeah, okay. Thank you.
To keep things on schedule we are going to go ahead and move on to the next presenter. Mark, if you want to step up?
Good afternoon. As Greg and Harry pointed out, this production ramped over the past four years, there’s been tremendous increases in the number of midstream crude oil opportunities. But I want to frame that up for you. So I think the increase in production only tells part of the story. I think you have to go back and take a look at what had transpired in the crude oil pipeline side of the business in the prior two decades. As production was declining in the previous 20 years, our pipelining capacity was being consolidated and rationalized and we were ramping capacity down as production was going down. And so we have taken the excess capacity and flipping it to alternate product service or in a lot of cases, we were just idling the pipeline abandoned and getting – for scrap.
So really what production side of the ramp up four years ago, the remaining infrastructure just wasn’t capable of accommodating the increase in the production. At Plains, we initially responded by low cost expansions and extensions of our gathering systems and trunk line systems. But once we fill those systems up, we pretty quickly transitioned to billing new gathering systems, new trunk line systems, new storage facilities. We’ve spent about $3 billion over the past four years on crude oil, midstream infrastructure in the U.S. And in some of the areas as Harry pointed out, when you take a look at the timing on the projects, our cash flow is still ramping up and we will reach a full run rate cash flow for a year or two until production in those areas start to build up a little bit more.
Our 2013 organic capital program in the U.S. is a little over $1 billion. If you run down the project, on the left hand side of the screen, the two things I would point out as you take a look at them. One we’re geographically diversified across the better shale plays and the second thing I would point out for those of you who have been coming for the analyst presentation for a couple of years is our capital program this year is much more weighted towards the transportation side of our business versus the facilities side that you probably saw in some of the prior presentations.
If you take a -- flipping over if you take a look at the right hand side of the screen, the entire U.S. or grant organic capital portfolio exceeds $4 billion that include a spend for 2013. And like the 2013 plan as you look at it, it’s geographically diversified across the major shale plays and that’s more heavily weighted towards the transportation side of the business. I’m going to spend kind of the balance in the presentation here both Roy and Harry talked a little bit about our business model. I am really going to focus on two steps within the U.S.; building or acquiring logistic assets strategic to market fundamentals and then optimizing the performance of those assets. I’ll cover four primary areas, the Permian Basin, the Eagle Ford, Mid-Continent and Rockies and then I’ll give you an update on our crude by real program.
As Harry told you, the Permian Basin is PAA’s largest footprint. We have a lot of assets in the lot of different places but our best footprint by far and away is in the Permian Basin. We’ve been leveraging that footprint for the last couple of years, enhancing its flexibility and opportunity. Over the past two years, we’ve constructed 300,000 barrels a day of trunk line gathering capacity in the Sprayberry and the Delaware basins. Now, really if you take a look in those two areas on the gathering side, what we’re doing is we’re coming back not that we’ve dealt those larger diameter gathering trunk lines, we’re coming back and building smaller diameter gathering systems to feed those projects and then we’re moving that production up into our major hubs; Midland and now Crane.
Kind of the main theme that we really sell to producers in the Permian Basin is that when you take a look at our footprint, our flexibility and connectivity we have in different areas, is that if you tie into our system any place in the basin, we can work your crude around to get it to any market you wanted to move it to. So we really sell that flexibility concept.
One of the challenges that we faced over the last two years is as Harry was pointing out earlier, Mid-Continent became bottlenecked price differentials in the Mid-Continent like Cushing was substantially lower than the Gulf Coast, and so as additional pipeline had to be developed, it didn’t make sense that developed that extra capacity go up in the Mid-Continent. He was pushing new projects were being developed to pushed out of the Gulf Coast. So one of the challenges we had to take a look at was how were we going to position our basin in Mesa’s assets to fit into that play.
And one of the things that we concluded in talking with other companies is that we really had the ability to transition from just trying to move barrels from Midland to Cushing to being an utricle part of these new projects that were being developed. What we’ve essentially done is if we’ve converted Mason Basin to a large degree to a very large feeder system, that’s a front end of all the projects are going to be feeding crude oil down to the Gulf Coast. We have agreements in place with the various companies that are sponsoring them from projects to provide about 1.1 million barrels a day of running capacity between our Basin Mason, our Permian line, our Permian systems to move to crude to.
I just want to walk you through those real quick so you can get a feel for where that 1.1 million comes from. If you take a look just going through I’m going to start out a little different order that are on the screen, starting back on the western portion of it, basically all the production that comes in to the basin system less the Midland. We come on now that comes into crane, we’re going to feed about 200,000 barrels a day out of the Odessa areas, south down to Crane to feed the long horn project. Moving over towards Midland then, we’re going to move production back down to McCamey to feed our own Cactus project which I’ll talk about in a little bit.
As you start to move East at Midland between Midland and Colorado city, we have 800,000 barrels a day of capacity between the two systems basin and Mesa. And when we get to Colorado City, we’re going to be feeding a couple of different projects. First, we’ve got 400,000 barrels a day available to feed the West Texas gulf project and then 225,000 barrels of capacity available to feed the Bridgetex system. Production that doesn’t move on to one of those systems will continue East all the way from Colorado City to Wichita falls. We’ve got a range that provides Permian express project with up to 150,000 barrels a day at capacity and then any production that still would like to move up to Cushing, we still have the swing capacity available but I think that gets back to the point that Greg was making before, I think the reality of it is, we’ve got five pipeline systems here that are going to be fitting the Gulf Coast. I can promise you over the course of any given year, one or more of those systems are going to experience problems. And when they do that, production is not going to be able to get down that system.
It’s going to back up in the West Texas again and it’s either going to wind to move to one of the other pipeline systems or it’s kind of one to move up into Cushing all the way through basin. So, the flexibility, the connectivity we have, we on the basin Mesa system, we think we’re really going to sustain a significant portion of the current cash flow of those systems just in a different matter. The barrels won’t be moving all the way up to Cushing anymore. We’ll be feeding along the system and dropping them off to the Gulf Coast export pipelines at different points along the system.
Unlike the Permian Basin, we had virtually no footprint in the Eagle Ford when the production kicked off. But we’ve developed, as Harry pointed out, a pretty significant footprint over the past 24 months. In 2011, we received a long-term commitment from Chesapeake and announced the construction of 350,000 barrel a day pipeline system from Gardendale to three rivers and then on the Corpus Christi. Later that year, we entered an agreement to acquire velocities gathering assets. In 2012, we optimized our position by creating a 50-50 joint venture with enterprise that combined our project with the Western portion of their Gardendale to Houston project.
Quite frankly we think the joint venture that we have in place with enterprise is the best mile strap in the Eagle Ford. It offered producers access to refineries in three rivers; Houston and Corpus Christi and excess to the waterborne markets at the lowest tariff in the Eagle Ford. If you take a look at the tariff structure and some of the competing pipelines in the area, I think what you’ll find is that our walk up rate is the cheapest pipeline tariff in the Eagle Ford right now.
Over the past 12 months, we’ve continued to optimize our Gardendale footprint by expanding our gathering assets, by acquiring USD’s rail facility. We’ve built an 80,000 barrel a day condensate stabilizer at Gardendale and we recently at the end of last year acquired Chesapeake’s gathering assets in the area.
We recently announced our Cactus pipeline project which is a 310 mile, 200,000 barrel a day pipeline system from McCamey to Gardendale. And what this project does for, it links our Permian Basin in our Eagle Ford footprints. Cactus gives Corpus Christi refiners access to heavier WTI and WTS quality crudes, allowing them to blend down some of the lighter Eagle Ford crude production and then back out additional imports. Besides giving Permian Basin producers access to the Corpus Christi refiners, Cactus provides an additional avenue for WTI and WTS to the waterborne markets. If throughput ramps up on the Cactus system, the way we anticipate it will, we’ll probably have to go ahead and expand the Eagle Ford system sometime in the next two years.
In the Mid-Continent like the Permian Basin we’re blessed with a large asset footprint and we’re uniquely positioned to capture some of the opportunities coming out of the Mississippi line, the Cleveland sands, and the Granite Wash areas. We used our ability, as Harry pointed out, we used our ability to convert an existing small diameter LPG system to crude service and that allowed us to secure commitment from producers that anchors our new Mississippi line production, our pipeline system. We then kind of as additional step, we use some of our Mississippi line pipeline capacity to re-wrap barrels off of the existing Mid-Continent system allowing us to do a low cost expansion of the Mid-Continent system.
We call this project our Western Oklahoma extension and it will add 75,000 barrels a day of capacity from rate Orion. It will transport production from the Granite Wash and sands to our Cushing terminal.
At Cushing, we continue to build tanks for both producers and refiners and to improve our connectivity and flexibility our terminal has most operational flexibility in Cushing meeting both refiner and producer needs. We seek significant demand for our services and Backwardate and Contango markets. And throughput is averaging over 700,000 barrels a day this year. As Harry pointed out a little bit earlier, we still have tank construction projects going at Cushing and we anticipate that we’ll have about 20 million barrels of capacity at the facility by the end of the year.
In the Bakken, Niobrara and DJ basin our strategy has been to develop the flexibility to export to premium markets by both pipeline and rail. The White Cliffs systems in which we own 36% has been operating very close capacity transporting DJ basin and Niobrara production to Cushing and it is a process of being expanded from 70,000 barrels a day to 150,000 barrels a day. We have two rail loading facilities in operation in the Bakken, one in the Niobrara and are constructing a new facility at Tampa Colorado to service the DJ basin.
That leads me into a little bit discussion, I’ve to give you an update on our view on rail, although I have to admit that and Greg has answered to one of the gentleman’s question. He pretty much covered most of the presentation on the rail component of our view anyway. And basically, rail facilities have been constructed to alleviate transportation bottlenecks either at various of rapid – production or they’ve been developed to provide refiners access to cheap sources of supply. Longer-term we expect pipelines to replace rail service in some of these areas as new pipeline capacity has brought into service. For example, we don’t see rail being a long-term solution for takeaway capacity in the Permian Basin or in the Eagle Ford. There is plenty of pipeline capacities in those areas to handle the production increases. We also don’t see it as a way of providing light sweet crude to Gulf Coast refiners.
There is plenty of new pipeline capacity coming down to the Gulf Coast. So even though rail has been a short-term solution in those markets, we really think that will fade out of the picture over the course of the next couple of years. For some producing areas such as the Williston Basin and for refining markets on the East Coast and West Coast, we expect rail to continue to serve as a long key transportation solution. The costs to develop pipelines out of these areas or to the East Coast or the West Coast are very high, and the projects remain challenged by the need for long-term producer commitments and in some of the cases they’re just limited end markets for certain types of crude and they’re better served by rail than they are by pipeline capacity. We do see demand to handle heavy Canadian production at some of our facilities but Dave’s going to touch on that in his presentation when it comes out with next.
I am going to walk you through just a little bit. As I mentioned we expect rail will continue to serve the Williston Basin has a long-term transportation solution. This side compares our Bakken forecast which Greg built up for you in the – slides to local refinery demand and existing export capacity by pipeline or rail. We feel there is ample – capacity to service future production growth. That said, there is over 600,000 barrels a day of new pipeline projects that have been announced. Presumably, to either take crude off a rail and put it back on the pipeline or to capture new volumes that we’d be produced in the future.
We don’t believe as Greg said that all those practices are going to go forward. We believe that Bakken producers will seek the highest net price for their production in rail, the Houston set pipelines to access premium markets primarily on the East Coast and the West Coast. And it’s pointed out, this trend is really having and if you go back and take a look over the past year, as rail capacity to premium markets on the East Coast, the Gulf Coast and now Northwest Pacific Coast have ramped up, volumes shipped on export pipelines to lower value mid-continent markets at loss volumes, significant volumes.
As Greg pointed out, one of our systems, Rocky Mountain system, one of our JV systems it had been – the system has been in full proration from June 2010 to June 2012. As pipelines or as the rail capacity opened up, we went out of proration entirely and right now, we’re only operating at about 65% capacity despite the fact that Bakken production continues to ramp up significantly. In the driver areas is what producer looking at is not the cost of transportation. They are looking at the mode of transportation in the market they can access that’s going to give them the highest net wellhead price.
This map is of our current and planned rail facilities and it reflects our view on rail. Our loading facilities are shown in white and unloading facilities are shown in yellow. We can load approximately 140,000 barrels a day at our existing facilities and we’re expanding to 265,000 barrels a day with projects on way at Van Hook, North Dakota; Carr, Colorado and Tampa, Colorado. We’re going to load 140,000 barrels a day at St. James and are expanding to over 400,000 barrels a day with projects underway at Yorktown, Virginia and Bakersfield, California. All of the new facilities are in areas where we expect rail to continue to serve as a long-term transportation solution.
Just give you a real quick update on overview of our Yorktown and Bakersfield project. Yorktown is our East Coast project. It’s designed to receive both manifest and unit rain cars. We’re going to have a capacity of about 140,000 barrels a day. At Yorktown, we’re modifying the existing dock and related infrastructure to facilitate loading of ocean going barges in small ships. We expect the facility is scheduled to be in service in second half of this year.
Switching over to Bakersfield, similarly – 140,000 barrel a day facility to handle unit trains but we will have some manifest capacity. The facility will be integrated into our existing California midstream pipeline assets and our terminal facilities in Los Angeles. This project is supporting the reactivation of our line 63 out of the – valley down to Los Angeles. That will bring about back in the service about 100,000 barrels a day of pipeline capacity. We expect to have the rail portion of the project in service in the first half of next year.
On a standalone basis, rail assets have benefits and limitations. But the value of rail is greatly enhanced when it’s integrated with our other midstream assets. By integrating rail facilities with our pipelines, our terminals, we can provide customers with a lag, a variety of flexible services in different markets and generate multiple revenue streams from different assets. Let me give you an example on it, I think it probably would clarify. I just got done talking about our Bakersfield project and some of the expansions we have going on in the Bakken and Niobrara. When you take a look at how we can integrate our facilities together, one of the things we envision based on having discussions with some of the Los Angeles area refiners that are interested in rail in Bakersfield it’s our idea of situation is we have a customer that wants to load out Niobrara or Bakken crude at one of our unload facilities in those areas. Rail at the Bakersfield, California unload at our unloading facility there. Putting in to one of our two pipeline systems in – south to refineries in Los Angeles and stored in tankage of one of our terminals in Los Angeles.
Under that set of activities or sequence of activities, we’re going to generate four different sets of fees in two different business segments. And that type of activity is just a huge home run for us. It really creates a lot of value. Beyond what other companies are just able to do with rail. If we can make an iatrical part of our other assets, we can generate multiple, multiple revenue streams out of it.
So, just kind of in summarizing, in closing, a couple of key points. Successful execution of our business model along with our existing asset footprint continue to generate many attractive investment opportunities for us in addition to providing takeaway capacity, our investments are also being focused on improving connectivity, flexibility and accessing multiple markets. We have strong visibility for continued growth as supported by a portfolio of over $4 billion worth of U.S. capital projects.
Good afternoon. I’m going to spend a little bit of time this afternoon talking about the strategies and some of the growth opportunities we see in Canada. PMC handles the Canadian crude activities and NGL activities in North America and is situated in Calgary. Similar to the U.S. information being provided today, the PMC assets are well positioned to track growth opportunities in Canada. For instance, the export capacity appears to be sufficient coming out of Canada but we see significant opportunities for both NGL and crude oil midstream assets. Since 2009, from 2009, 2012 we spent, invested over $2 billion in the North American NGL market and the Canadian oil infrastructure. That’s going to split approximately 1.4, greater than 1.4 billion on the NGL side and in excess of 850 million on the crude oil side.
In April 2012, PMC was able to close the $1.68 billion BP NGL acquisition. This was an asset rich acquisition and it provide us with significant complimentary assets to our existing NGL platform. We’ve mentioned in the past that BP use these assets as part of proprietary system and its – plan to change this and to create opportunity by optimizing the assets through third-party fee-based activities, using them for alternative services and also integrating them with our existing PMC demand-base platform. Our operational integration is complete and to date we found no major surprises in need the assets. We still have IP integration continue through 2013 which was planned as per the original business model. The assets are all performing in line with acquisition forecasts and our focus now is trying to extract commercial synergies. We’ve indentified a favorable number of attractive asset optimization opportunities on both crude oil condensate and NGL.
We were expecting to see significant investment opportunities and we have discovered those and now starting to read benefits up. In 2013 our organic growth investment is going to be about $290 million, spread over a number of different assets. The pre-owned or the pre-2013 investment in 2013 projects is about 255 million and we have approved project total of over 630 million. We also have a significant portfolio project list of about $2.5 billion to $3 billion. And as you can see the majority of this close to 70% will be on the NGL side of the business and the remaining being in our crude oil, Canadian crude oil business. It’s also split, the majority of the projects are both in the transportation and facilities sector.
Following up on the PAA business model, our model is exactly the same in terms of building, acquiring, optimizing assets for current and future needs. I’m going to talk about four of our strategic areas today being in the Northern Alberta area, the Pembina/Cardium, Sarnia and our Rail business. The Northern Alberta strategy is centered around the rainbow pipeline. Rainbow pipeline we purchased in 2008 for $687 million. It runs from Edmonton on to Zama which is very close to Northwest Territories. The capacity on the line is about 220,000 barrels a day. It’s currently running at about 145 barrels a day.
We expect in the local area, round the rainbow pipeline that the heavy and sweet crude productions will increase about 100,000 barrels a day over the next five years. So we see that this will require additional diluents and midstream transportation infrastructure to get this crude oil to market. We’ve indentified over $600 million of portfolio projects around this area, some of which will include the $260 million Rainbow II pipeline which Harry mentioned before is condensate and detained line running north from Edmonton to Nipisi, about 187 miles. We expect that pipeline to be up in early Q3 and expect it to be on time and on budget.
Second project we’re working on that area is approximately 280,000 barrels of storage up at Nipisi at a cost below $30 million that will help us facilitate the batching of project from Nipisi down in the Edmonton market. We still believe even after these projects are done, that there will be significant opportunities in various stages for us to develop. We expect to extend and expand the rainbow system north to capture new productions being developed in that area. We expect that all be at third-party long-term contracts. We expect also to be able to construct additional crude oil and condensate storage in Edmonton again to handle the increases in production.
The third development opportunity is we expect it will be able to deliver or to develop a rail facility up at Nipsi and for degrees – mark and Harry described earlier that that will evolve us to expand rail base. These projects will all provide third-party tariff at gathering revenue for us and also commercial optimization upsides.
The Pembina/Cardium area is situated around two of our other pipeline systems, the Rangeland pipeline system which runs from essentially the U.S. border to Edmonton and the Co-Ed system which was bought, which came over on the BP asset, which runs from just west of Calgary to Edmonton. We have portfolio projects above $40 million planned for this area and we also see significant light crude increases in production moving from 200 barrels a day in 2013 to 375,000 barrels a day in 2018. The idea that we have there is to increase the volumes on our existing pipelines through asset optimization. So what the initial programs are going to do is take the condensate volumes that are batched on Rangeland pipeline today and moved them over to existing condensate pipeline on the Co-Ed system. And what that will do is allow us to free up about 15,000 barrels a day of space for additional sweet crude. We see numerous opportunities between these two pipeline systems where we’re going to be able to de-bottleneck them and expand the main lines and deliver this into new areas and build new connections.
Starting – I will talk a little more detail later is it’s a critical NGL hub for Canada. But we believe it has the potential to provide crude oil storage services as we increased the amount of crude oil to transport these. Our planned areas to utilize our incremental storage we have a situation where we have excess brine right now so, a lot of the brine is stored in the caverns as we’re able to reduce the excess brine and take that out of it. Our new caverns we’ll have excess caverns that we don’t require for the NGL system. So we expect to put in approximately a million barrels crude oil storage into that area. The idea will be for us to source this crude from Enbridge’s pipelines line 6 and line 5B and then move it an existing 8 inch pipeline into our storage and that will create flexibility for operational storage and also the storage of discounted products.
Once the storage is complete, we’ll also have the ability to convert to existing lines of 6 inch line and 8 inch line, and if required, build new connections and service these area refiners. The new connections would have to build would be to service the line 9 if that demand --.
Just expanding a little bit on what market indicated. We see exactly e same situation in Canada in those markets and in the U.S. market is that the pipeline constraints are creating rail opportunities. PMC today has approximately 500 cars under lease and we expect by the end of 2015 to have about 1050 which we expect that will translate into about 30,000 barrels a day of crude moving out of Canada on rail.
Today we are utilizing our all third-party rail loading facilities and are starting to develop our own rail facilities both in Alberta as I mentioned at Nipisi on the rainbow system and on our and in Saskatchewan on south pipeline system. We very much as Mark indicated are focused on the long-term sustainability of rail movements and so our focus is going to be in transporting rock crude, crude that does not have, has very little diluents in it and also what we call the high 10 crudes which are heavy crudes in Canada with high 10 factor which have a significant discount over the standard WCS. Our plan was also to utilize market system and deliver into the premium terminals we consider which would be on the West Coast, East Coast and St. James.
Switching over to the NGL business.
Similar to the crude oil position significant increases in North American NGL have occurred and it’s our expectation that this will continue and that exports are going to be required to move to balance the market. There are four pricing hubs in the NGL system. There is one located Belvieu, one in Conway, one in Edmonton and one in Sarnia. The Edmonton pricing is based off Conway prices and the Sarnia prices are based on Belvieu. The majority of PMC supply comes from the Edmonton area or the Fort Saskatchewan area, so that is all Conway based product and our objective and our goal is to move the vast amount of that product either via pipeline or via rail into the higher prices eastern and southern markets where there is increased demand and it’s also higher priced in their base on Belvieu.
The three major pipeline systems that move out of Canada and out of Fort Saskatchewan, the alliance system which moves a wet gas with NGLs contains within it that line moves from essentially BC into Chicago area where the NGLs are fractionated and then moved into the market spec product. That’s a system where the NGLs, the spec products are controlled by BP, other long-term contracts. The other system coming out of Canada is the Enbridge system, you’re able to move Enbridge, move barrels down Enbridge from Fort Saskatchewan to Sarnia. Enbridge is a common carrier system but it’s a system -- the only way to move barrels along that system is if you have storage at the inlet at Fort Saskatchewan, you have breakout tankage at Superior, and you have receipt tankage at Sarnia. So, essentially there is only two shipper who is right now shipping on Enbridge with NGL and Plains is the majority shipper about volume.
The third alternative out of Canada historically has been the Cochin pipeline and it moves again from Fort Saskatchewan, moves through the upper Midwest and moves down to the winds of Sarnia area, moving specification product, mostly propane and where this is a system that was used by the majority of the shippers and producers out of Canada to move the product into the higher pace markets.
As you’ve seen that’s been announced in June 2014, the Cochin pipeline system will be reverse and essentially from Chicago back to Edmonton we are running condensate service. This will be a significant change to Canadian market and we already see significant extra volume showing up at Edmonton and when Cochin pipelines reverse, we expect to have even more volume here. This is going to force the Canadian producer and the Canadian midstream people to look very aggressively at how do we incorporate West Coast export option in to handle the excess supply. The changing dynamics for the PMC assets are sure that we are very well positioned to create opportunities.
Changing over to the Canadian market and looking at the dynamics of that. Canadian NGL supply could increase by 300,000 barrels a day over the next five years to a total of 1.1 billion. These production increases are expected to come mainly from the Montney/Duvernay and the Pembina/Cardium plays. And I’ve always seen gas prices not really support the robust drilling activities. The JV economics seem to be influence producer behavior and what we’re seeing JV such as EnCana with the Mitsubishi and PetroChina are forcing ahead these projects even though the economics are a little bit shaky.
On Marcellus and Utica, our expectation is that the majority of that product will get fractionated in the local region and that we do expect to see some of that production served further into the Northeast market and we do think that that will have some limit on the amount of Western Canadian product moved into Sarnia which will keep it more at what we’ve seen in historical levels.
On the demand side, condensate demand continues to grow in Canada. We expect it to be up by 225,000 barrels a day by 2016 and have continued growth after that. Butane we expect to see small demand increase to be used dealing with in heavy oil it’s less than 4% but overall, we expect the butane to be in an oversupplied situation to Edmonton as well. Ethane; the Canadian chemical producers at Sarnia and at Geoffrey and at Edmonton are currently sourcing new ethane supply to complement existing infrastructure and potential expansions. We basically see that market as being close to balanced.
On propane, we’re seeing a few new demand potentials coming in. Williams has announced propane dehydration of PDH facility at Fort Saskatchewan who expect this to come online in 2Q ’16 with a nameplate capacity of about 25,000 barrels a day. We also expect the Canadian chemical producers to continue using propane as a swing commodity fill up capacity when the market conditions are right but again this will be very price sensitive to relationship between propane and ethane.
In general, propane, we expect the increase in production along with the reversal of quotient pipeline in 2014 will result in substantial excess amount of propane in the Edmonton market. Historically, probably except for the last two years the Edmonton market has been, tends to be the lowest price market in North America for propane and we expect that trend will continue and again this will put added pressure on the Canadian industry to develop export alternative preferably on the West Coast. For infrastructure, our asset base and business model are well suited to capitalize on C5 shortages and the excess we see in the C3 and C4.
Focusing on the NGL strategic areas I want to talk a little bit about today on the Montney/Duvernay but our plans are there at Fort Saskatchewan, our eastern area and our U.S. facilities. The Montney/Duvernay project that we’ve just announced is the Western reach project. This is a pipeline that’s going to run from essentially Gardendale to Fort Saskatchewan approximately 350 miles. It’s a joint venture pipeline with Keyera which PMC will construct and operate. Pipeline will be, it will be two pipelines, an NGL mix line and a condensate pipeline. We’ve recently just completed a very encouraging open non-binding open season and had over 28 producers nominate volumes to us on that line.
We’re undergoing detailed engineering views and cost estimates at this time but we do expect that this pipeline should go ahead will be, will cost around $700 million for the PMC, 50% share. Some of the advantages we see of this project over some of the competing projects is that this will provide access to both PMC’s and Keyera’s asset to Fort Saskatchewan for fractionation and storage and that is one of the significant problems we see going forward in Canada that we may have the pipeline capacity to get to Edmonton but we need to match up the fractionation storage there as well. So this is an advantage that we’ll have both parts at.
The second big advantage we think we have over competing projects is the access that Plains and PMC is able to provide to producers and shippers on this line. We are able to take market, product out of the market, take it down to our Eastern delivery system at Sarnia. We’re able to take it down to our existing PMC U.S. storage terminals. We have numerous crude oil storage facilities that can use blending material and we potentially re going to have the ability to take it to the export market as well.
Fort Saskatchewan area and the Fort Saskatchewan terminal is something that is very important to us and we’re excited about the growth opportunities that we’re going to have up in that area. I’m going to talk today a little bit about our storage assets there, our connect ability what we want to do and also about our fractionation position. As I mentioned before, this is going to be one of the critical topic for the Canadian NGL industry as getting this product fractionated and moved to market. Right now at Fort Saskatchewan we have about 6.8 million barrels of cavern capacity in our 100% owned Plains Fort Saskatchewan facility. Again we are only using 2.5 million barrels of that storage due to lack of brine storage. So one of our projects has to add bring storage to that facility which allow us to have additional caverns that are very low cost and very quickly. We also have another million barrels of net cavern capacity in the PMC operated Fort Saskatchewan JV and we have another 1.9 million barrels of net cavern capacity in the Keyera, Fort Saskatchewan or the KFS facility.
We believe that the storage opportunities are going to be needed to accommodate new production sources and then basically be needed to stage production whether it’s for condensate into the heavy oil, into the heavy oilfields or to move propane out to export markets or the U.S. markets. We see an opportunity create a storage out for condensate ethane and NGL at the Plains Fort Saskatchewan facility. There are existing hubs up there for condensate and ethane and NGL but we, the industry has given us indications that they would like to see more than one facility. We have the potential to expand our cavern capacity by about 7 million barrels and we can do that through a combination of washing new caverns and just bringing existing caverns back into service once we have our brine handling capacity.
This opportunity will create new storage opportunities for ethane, propane, butane condensate and potentially ethane. We are in the final negotiations for several long-term third-party agreements for significant volumes of storage on all three products. The other thing that the goal of our is to have at Fort Saskatchewan is to enhance the connect ability and deliverability to further enhance our condensate but Fort Saskatchewan. We want to increase utilization of our storage capacity by sourcing product from as many plays as we can. We’ll be able to source product from existing lines which we’re already connected to. We’re already connected to the Cochin pipelines, southern light have rail and potentially we’ll have western reach condensate volumes coming in as well.
Going out of the facilities we have existing connections already for Cold Lake access, Rainbow II and we’re finalizing third-party condensate connections to Fort Saskatchewan for all the other major pipelines. On fractionation, we’re in a very good position at Edmonton. We have 95,000 barrels a day of fractionation capacity at the 100% owned Plains Fort Saskatchewan facility although we’re only utilizing 45,000 barrels of that in the current configuration. We also have 6.5 million barrels a day of net fractionation capacity at Keyera operated facility.
Based on the demand we believe we’re going to be able to expand this, quickly expand the usable fractionation capacity through low cost de-bottlenecking. We can add up to both 50,000 barrels a day of capacity in phases. Phase I for us would be a 20,000 barrel a day capacity addition that would take two years and cost about 30 million. This should put us in the position that we should be able to be the first to market with the lowest cost expansion in the area.
The eastern area NGL opportunities, the insert that gives you an idea of what our Eastern assets are today. Essentially we have a group of pipelines we can EDS and EDS essentially connects Green Springs, Windsor, Sarnia and St. Clair. We see the potential for using this eastern system, eastern storage and pipeline assets to deliver Marcellus and Utica production to petrochemical and NGL demands in Sarnia. We also see the potential for the Windsor Ontario storage to serve as an Eastern area hub for ethane, butane and condensate. And what we’re looking at there is that our idea is to construct pipelines from the Green Springs are down into the Utica. The idea would be to bring Ethane volumes up Green Springs moved on the EDS systems south which is underutilized today, creates storage for the customers are Windsor and then provide deliver into the petrochemical facility for BR, the Plains’ own WSP line.
On butane, the idea we would have there is it the butane storage would just replace the storage. It’s not accessible anymore in the Sarnia area for refiners. And on condensate we’re looking at moving the excess, the condensate that’s produced at the fractionator in Sarnia as well as any other naphthas in the local refinery areas and move those barrels again down. EDS system stored them at Windsor, put them on rail and moved them back to Western Canada to our Fort Saskatchewan complex.
I also wanted to just utilizing our existing NGL footprint. We want to continue to commercially utilize the BP NGL assets with our PMC legacy assets to establish a fully integrated North American NGL platform. We want to expand our facilities to meet the growing demand and maximize the return on our assets. Couple of projects we have on our existing legacy assets are as we have a new, we have an expansion to accommodate an NGL pipeline from the OXY Elk Hills Field which we expect to be in service in Q1, ’14. We also have a couple of projects we’re looking at the Phoenix area, into our Bumstead storage facility which would be the idea of expanding the storage assets in the potential for propane pipeline towards the Mexican market. We also want to continue to expand and build our rail infrastructure for existing and new NGL facilities.
In summary, we just wanted to echo March’s comments. We believe the PMC asset base is very well positioned to service areas of expected Canadian crude oil NGL growth with the PP&G acquisition as operationally integrated. It’s performing in line and with expected economics at the time of acquisition and it’s providing better than projected asset optimization organic investment opportunities. The current environment provided PMC’s business model and asset base continues to provide significant organic investment opportunities.
We’re going to go and start the Q&A session now.
Dave, you’ve mentioned that you expect NGL supply from Canada to increase by 300,000 barrels a day over the next five years. That sounds like an awfully big number on the existing base. Could you tell us what your forecast, what’s assumed to make this happen in terms of price for gas and price for NGLs?
I would say that that production increase would be a very optimistic forecast. And that essentially assumes that all the projects that people are looking at would go ahead.
In terms of the gas price together
Same gas price?
Yeah. And I think that would be basically just on current gas prices that they go forward on.
Just out of ignorance I guess, up in Canada, today you utilized butane you talked about there is going to be excess and surplus butane. Today also you use butane to blending for gasoline where it might be either opportunities for you or to sell to people that try to make that kind of a spread, and if not, it’s something waiting for the commercialization basically we really need to see if the develop some kind of export terminal on the West Coast of Canada to alleviate this issue of the excess capacity.
The first question was, just as use is beating use for winding and gasoline, yeah, it’s used a little bit in gasoline but not nearly to the same extent that it is in the U.S. where you see the major blending facilities all over that has not been developed yet. And so your question was on the export facility?
Right. To the extent that you’re going to create all this access you mentioned that you’re waiting for the commercialization. Other than the hope for export facility in West Coast, what do you think needs to transpire that all help absorb locally the excess NGLs or is that additional suppliers are going to come into the U.S. market?
Yeah, I think if the export facility has not developed on the West Coast, you’re going to see two things. You’re going to see more of these PDH facilities built at Edmonton, there is a number of – are looking at doing facilities up there as well. Because we think the price will be lower enough to justify those. The other choice is to force that market in to the U.S. market, into the export terminals that exist on the Gulf Coast so we would see product and we’ve already seen a bit of product this year go all the way down to the Gulf Coast and be exported.
I have a question here. Is there adequate rail capacity north of Edmonton?
Sorry, is there ample?
Adequate. For NGLs?
Well it could. Anything tracks, yes. Where the system goes, essentially right up to Fort McMurray so there is track available and high quality enough track to move unit trains of crude oil and NGL if you wanted to.
Just I’m curious on with the integration of the natural gas or the crude oil pipelines and rail facilities and terminals, does that create additional opportunities to optimize through your supply and logistics, I mean effectively trade around those assets?
And if you could describe a little more how that would work and what the opportunity would be?
Yeah, there is definitely, I think where the opportunity exists beyond creating the harvest of 7 degree is that when you integrate the pipeline and the rail assets together in the storage facilities, it creates the opportunity for us to break different grades of crude from different areas of the company with different price differentials associated and custom blend on the metal distillation spec for our refinery. So yeah, I think those got arbitrate opportunities available if we can integrate the pipelines. One of the projects that you guys have trying to develop is rather than strictly looking at the rail facilities just to lower local production, but in some of the areas up in the Rockies where we have pretty significant pipeline systems coming down out of Canada and stop with me to bring Canadian crude down in the U.S. blended, they can meet customer respects and then move that out.
I think this probably, we think there is a good opportunity to develop some of those type of custom blends from West Coast refiners in lieu of our those in our Bakersfield rail facility in next year or two.
We see tremendous opportunity between Canada and U.S. as well. If Canada has got supply disruptions or pipeline breaks through shut ins or whatever the problem is, we’re going to have excess crew that we are going to be able to put on rail, back up crew that can go into U.S. pipeline system and deliver that. So, we’ll see those opportunities going both ways on a regular basis. The rail will give us really a North American approach to the whole infrastructure business.
Harry, can you talk to me about how long-term your contracts are in some of the rail facilities that you are getting, how much you are going at the third-party customers versus keeping for PAA’s S&L stuff? And I guess based on the contract tenure that kind of returns you’ll target on the rail facilities versus let’s say a pipeline project and the --.
Yeah. The rail facilities that we own are a combination of commitments from our own supply & logistics division and supply & logistics efforts and third parties. So I would say it’s probably in the neighborhood of 60% or so is third-parties, isn’t that right?
Yeah, I think so.
40% is for internal use. The loading facilities are probably a little more geared towards our supply and logistics segment, and unloading facilities are little more -- currently are a little more geared towards third-party service. Then from the term standpoint, we have anywhere from one year to five years on the rail facilities and couple of parties actually have extension rights as well. So, some of the third-parties could actually use those facilities for 10 years to 15 years.
Harry, you are talking about the commitments, right? One to five year commitments?
Yes. You are saying third-parties to use our facilities, was that?
And then I guess the returns would vary based on sort of the tenure of the commitment, is that fair to say?
It is. So I think it’s consistent with sort of the mid-teens type returns in total.
Any other questions? Okay. I’m the – section here.
Thanks. There’s a statement that the PAA based in Mesa system can substantially preserve their current profitability even as third-party expansions come on line to the Gulf Coast. Does that include or exclude the economic returns that you expect out of the Cactus Pipeline project?
It includes it.
Includes it, okay. And then secondarily there was another comment that said, you’re still building Cushing storage capacity at this point. Rates have come down year-over-year. At what point does that become a little bit less economic for further expansions on Cushing storage to happen. I mean what price per barrel per month would you kind of start to reduce deploying capital in that area?
Well, I think maybe one easy way to look at it is, if terminal capacity is $15, $20 a barrel to build and you’re targeting mid-teens return, that’s $0.25 a barrel a month type of range to get a mid-teens type of return. I’ll point out that sort of the comment that Greg made earlier, we probably never have been the highest price terminal in Cushing, that’s mainly because we have tried to steer away from attracting sort of traders in the terminal, it’s mainly been for logistics, logistical needs, operational needs. So, I think our long-term commitments have always been more reasonably priced. As Greg said we’re never trying to extract the last dollar out of it and we think we’ve positioned ourselves for a long-term utilization of our terminal and we’re continuing to see as market mentioned demand for expansions from our facility why you would think, and total demand would be shrinking. I think it’s depending on everybody’s position in Cushing. We are -- I said really largely an operational terminal. Mark you want to?
No. I would say obviously, when some of the other terminals that have been built over the last couple of years, I view them being more as Harry pointed out designed to bring barrels and park them for traders that wanted to play Contango storage. That’s really not what our facility is about. I mean we do store like anybody else does, one of the structures there right, but by far in a way our terminal is driven by third-parties, and to a large degree by refiners we’re bringing barrels in. We have connectivity to all the major inbound and outbound pipelines. And we’re bringing barrels in and it’s really driven more by refinery throughput than in this crude oil market structure. The other thing I want to talk about additional tankers being built is that’s been one of the benefits of both the Seaway, the reversal and corrosion and the new -- pipeline. There is more barrels that are going to come down that have to be staged to feed in the low systems. And we are building a high speed delivery manifold to be able to deliver in both systems at for line rates. So we are seeing incremental demand for tankage out of customers that are going to be shipping on those two systems.
Any other questions?
You mentioned $2.5 billion to $3 billion of capital expenditure product, that’s for Canada alone?
Yeah, for the Canadian crude business and the North American NGL business.
Any other questions? Let’s get ready for the break. We will take about a 25-minute break here and so we’ll convene back about 3:05. On the podium is Dean Liollio who is President of PAA Natural Gas Storage, PNG. Dean?
Thanks Roy. In my part of the presentation, I’m going to cover our current positioning; I’ll give you a little overview and history of PNG. And then will spend most of my time on the outlook for the future. With me when we get done with that, for Q&A, Ben Reese, our Senior VP and Chief Commercial Officer with PNG will join me for Q&A. Roy touched on this briefly, but current ownership structure of PNG 37% of the LP interest is owned by the public with PAA owning the remainder and all the GP interest. As far as 2013, PNG represents 6% of total PAA adjusted EBITDA. If you look over to the right side of the slide, PNG’s aggregate size and yield, enterprise value about 2.1 billion, equity market cap of 1.6 and current yield of 6.6% that was last week. I think right now we’re yielding closer to 7%.
If you look at our public guidance, 2013 is at 120 million of adjusted EBITDA with distribution coverage of 102% with that number. Interestingly enough, in 2012 we had the same mid-point guidance of $120 million. If you think about that for a second, take into account contracts that roll off each year and then new ones coming in clearly higher price contracts rolling off, newer ones coming on at current market rates. I feel that’s a pretty good number to put out there year-over-year.
Little bit on our history, for those of you who aren’t familiar with PNG, back in ‘05 PAA entered the natural gas storage sector with 50-50 JV with Vulcan. Natural gas storage shared many of the characteristics of the crude oil business mainly when we thought -- when Greg, Harry and the group thought about it, really looking at what was done at Cushing early on and focusing on Pine Prairie, a lot of similar characteristics there. So, from ‘05 to ‘09 a lot of construction going on. We completed the construction expansion of Bluewater facility, built Pine Prairie up from scratch. There was nothing out there. Currently it is probably the largest salt dome facility in North America and then, added a satellite facility to Bluewater. In September of ‘09 we acquired Vulcan’s 50% JV interest and we set the ground work for a separate management team, totally focused on natural gas storage. In 2010, we initiated and completed the IPO of PNG based on a high organic growth platform and the opportunity to consolidate natural gas storage opportunities using a common currency. In 2011, in February we acquired the Southern Pines Storage facility.
Now, it was a sound long-term strategy but we certainly misread the impact of shale gas on supply, on price, and ultimately on storage and the value of storage. Just to on slight of it, crush bases differentials, crush spreads and her volatility. And you saw the market fall really over the three years, about 60% storage values declined. Weaker economy delayed a lot of the demand growth coming on, but during that time, PNG has performed well in a very weak market raising its distribution 6% and generating over one to one coverage on its unit distributions. And I think the key to that certainly is our low cost organic growth which I’ll show you in a second.
The other thing I think we accepted early on and many others probably in the industry weren’t as quick to as one of the keys here, once we were in this market, we thought, we went ahead and contracted a lot of capacity out. It probably what folks felt was lower rates at the time, but I think in hindsight it really has set us up to endure the current conditions we’re in.
So, where are we today? Low spreads, low volatility, just a lack of fear in shortfall of supply, it’s a tight challenging market. And we’ve been there. We’re still two years to three years out from demand coming on and I’m going to touch on those points in a minute. But we’re still a couple of years tailing at 2015-2016 as we see it with a substantial demand coming on.
How we’ve positioned ourselves in the market? First, our assets are strategically located, approximately 88% of our 2013 guidance is attributable to our portfolio storage contract. We have very disciplined execution with the proven commercial and operations team, and clearly a solid foundation with a very supportive parent in PAA. Look to the right over there and this looks very familiar to this chart. If you were here last year that we showed actually with a little bit of improvement, 2013, 95% contracted; 2014, 80%, I believe last year we were at about 70, and then in 2015, 50%. This is that cascading effect basically on an average of three year contracts rolling off and getting re-contracted. If you look at the top bar, the little white piece up there that’s the projected expansions for 2014 to 2015. Right now we’re at about 97% Bcf and at the end of 2015 that will take us up to about 112 Bcf. And very low cost even in this environment produces high-teen returns and… so if you look at this that’s really the key to how we’ve been able to sustain and execute in this market.
It’s one of my favorite slides. I don’t think too many folks can put one up here like this. To the left you see what rates have done since really the ’07-’10 period till today at 60% decline on average. But when you focus over the right, we’ve had a 26% compounded annual growth rate that includes the Southern Pines acquisition. Adjusted EBITDA really going from about 30 million to 120 million, but our average working gas capacity in those low cost expansions have really carried us through and helped us weather the storm. So in this market to be able to produce these kinds of results, I think it takes some solid execution. So, I’d leave you with one thought on here, if you like what this looks like in this type of market, imagine what could happen if the market starts to change.
These are credit metrics, solid balance sheet. What’s missing off your deck is over the right the targets were well within our targets, but a good solid balance sheet well within our credit metrics.
Now, looking forward, I’m going to talk to you about some scenarios that we see that could be out there and kind of walk you through it, the drivers behind them and the implications that they have on storage. So, first, I’m going to start bottom and work my way up. Moderate demand growth, projected demand just takes longer to materialize than what all the groups out there would make everyone’s forecasting. The market remains balanced, pretty much status quo of where we are right now. Demand is coming, but let’s say it doesn’t come by 2015 or 2016, let’s say it takes longer. That’s a type of scenario I’m talking about. Industry consolidation is going to intensify then we’re going to test folks’ lung capacity or as Greg likes to say who can hold the breath to longest. It really will take shape then and you’ll see it if we stay in this environment, I think the highly contracted portfolio is key and you have to have optimization skills and capabilities to work through this type of environment which PNG does.
Let’s take it up to the next and talk about the solid demand growth price-driven power gen, adds steady industrial growth particularly on the Gulf Coast. LNG exports are a reality. They happened, lot of announcements, they are all fall -- all the pieces are falling into place but let’s see it, let’s have it happen. With that you’re going to get them on the storage side. You will get what I’d call modest market recovery, improvement in seasonal spreads and volatility. Those who have grown low cost storage are going to be rewarded for it. I talked about the returns we are getting right now on that $3 million to $5 million a Bcf. In this environment you are going to see rates rise, you’re going to see more hub services, you’re going to get better returns. But location is going to matter. It’s going to be very critical and I’ll dive into that in a minute.
And then scenario A) substantial demand growth. We’ve got regulated and price-driven power gen. In other words power gen in not coming on just because natural gas prices are hovering around 4 bucks. You also get -- have all the regulations take place. You got to switch and I’m not talking about – the gas switching, what is it going to do this year, this is permanent switching. It’s already on the map but you’re going to see a kick off there. Significant industrial growth, it’s the price environment, call it the $4 to $5 range, there will be growth.
Several plants announced, I’ll go through some details, it’s in our appendix. And expansion of the LNG export market not only a reality, but growing and it doesn’t take much. Even if you, all the projects I’ll show you, even if there is just a portion of that, it’s got a lot of impact. So meaningful market recovery, what does that mean? I think in this type of conditions you’re going to need additional storage particularly in certain areas. Demand returns for multi turn storage. Power gen guys haven’t changed. They still need multi turn storage. So you just have more of it.
LNG requires multi turn storage. So you’re going to get a premium I think for facility performance and deliverability in those kinds of conditions. Where do I think or where we think PNG and where we lineup is pretty much in B. I think we’re there with some upside. I think we could some A, but it feels real good about the B scenario and possibly with a little upside in A. So, as we go forward. And really when will this manifest itself? We see it as late 2015, early 2016. I think the catalyst is when the exports start flowing out of Lake Charles.
So Power gen, if you look at where we are now, going to what’s just on the map for 2017, we have about 6 to 7.5 Bcf of growth just from Power gen, and I’m talking about permanent switching. And really most of it occurs to the East, North-East, Southeast that area and you say, your storage facilities aren’t right there, they don’t have to be. Look at the pipes that are connected to Pine Prairie, Southern Pines, Bluewater and those pipes serve most, the vast majority of where these power plants are going, those big chunk plants. So really it’s, what pipes are you connected to, where is your storage located, not necessarily where the plants are going in.
PNG itself does not have to be directly connected to these, but certainly the market is going to feel that impact. Industrial 95, new U.S. manufacturing projects, $90 billion plus investments. Just on the Gulf Coast alone about 2.5 to 3 Bcf by 2020 of growth right there. Those two coupled to get about 10 Bcf of growth. Let’s kick it up on that and talk about LNG exports, already approved 3.6 Bcf, that’s just a bean pass and free port. There is a line in the cube, even if you are conservative and say 6 Bcf add all these projects comes into the Gulf Coast. Now you’re talking about 15 Bcf to 16 Bcf of growth per day, put it into perspective. Right now on average we’re at about 70 Bcf a day. This is a 20% bump. Supply can keep up, it can do things but it’s going to create a lot of volatility because this type of growth is centered in certain parts of the area and you’re going to need a storage to manage that type of growth.
The other big point down here has nothing to do with the demand growth, but a change in what’s going on right now in the grid. Take careful attention to this. Few years ago we showed a slide with a big red arrow going from the Gulf Coast up to the Northeast, that’s starting to change with Marcellus and Utica. You’ve already had announcements of projects turning around, that’s the smaller area to the left. But this shift, these little shifts right there take close attention to each announcement and I’ll go through them but they all have impact and change the dynamics. Bases differentials change, just when the pipe was built from, all the pipes were built from the Barnett, Fayetteville across to the Southeast across the bases, these little changes have an impact on basis differentials and the value of storage if you are sitting in the right place.
So let’s take a view, Power gen 6 Bcf to 7 Bcf, that is the area where it’s concentrated. Couple industrial development just right down there in the Gulf Coast at our doorstep, another 2.7 Bcf. LNG exports just take 6, those are the numbers. Now let’s look at pipeline changes, there is a FPL’s announcement bringing another line down into Florida for their Power gen use more security from Transco 85 down into Central Florida. Right there is Williams expansion and -- announcing expansion, Southeast headers announced an expansion. So they seem all really targeted to that Florida market most of them.
CGT line reversal, 500 Bcf potentially could go to or 500,000, potentially can go to 2 Bcf a day, that’s the kind of capacity. But just what they have now half of B, turning around bringing gas from the Marcellus down to the Gulf Coast, really right through Pine Prairie. It’s one of our big interconnects. Now what’s interesting, two announcements here, you’ve got trunk line and boardwalk announced that they are switching to NGLs and those type of things. They were in that gas. Now you see them, now you don’t. Big impact there because even though what we can show all our FSS agreements and take care of our firm customers, all that excess infrastructure capacity that’s out there goes away.
Suddenly storage becomes more critical when you take some of those pipes out of the equation and it doesn’t take much. So, that’s where our assets sit with all this activity. We are in the good spot. What’s really changing for us though and specifically when talk to you about Pine Prairie because a lot of what I have mentioned really directly impacts Pine Prairie. It is our -- we have the most growth opportunities there and clearly we’ve made all the investments to do it. So, location 50 miles from Henry Hub in the fairway for all this industrial development, close to Cheniere’s Creole Trail pipeline. Cheniere already did a filing announcing that that line would come into Pine Prairie.
Flexibility, you see below we’ve got the nine interconnects, eight big pipes and these are all 30-36 inch, still all the good liquidity, all the things that customers love exist right there. And you’re going to need that to serve this market. Expandability, if you look down at the lower right, right now we’re at about 45 Bcf. Clearly our plans for low organic growth take us to 53. We’re permitted to go to 80, and certainly, we have the opportunity to make it as big as we want. The need thing here, really I call it need is, yes others have this capability but we think we do a pretty good job here and have developed a consistent pattern of bringing our storage on time given the investments we’ve made. So, little overview here of our facilities; PPEC, Pine Prairie, Southern Pines, Bluewater, the value drivers demand other, it pretty much check all the boxes. The big change is down here. Currently, Pine Prairie and when it was built, it was the supply hub type storage facility, really taking Gulf Coast supply and sending it up Northeast, that’s the way our customers who got in, got stores there were flowing things.
What’s changing and what we’re seeing right now is Pine Prairie is transitioning to a market hub facility, showed you where the market’s going to be and we’re really seeing this evolutionary change. With that more hub activity, clearly I think market based storage over history and I think it will show itself is has the premium over supply base storage, it’s just the fact in the area. And I think you’re going to see this transition occur over the next few years when this demand kicks up. So PNG’s view for the future. I think disciplined execution and patience is required. We still have a couple of more years to go through. So near-term, we are still going to have robust supply, spreading volatilities low, slow but steady demand growth, it’s just going to take a while, spreads are going to lag but storage capacity additions are going to be limited.
Few years ago we showed a map of all the projects up there in all the areas. You look at the map today, they are gone, they only people adding storage are incumbents and really well positioned incumbents. Consolidation opportunities; if we sit in this environment much longer, we’ll test everybody’s lung capacity, we’ll see what comes up here. But I think they are hunkering down now, but talk to me in a couple of years we’ll see what’s out there. PNG positioning, highly contracted storage capacity, low cost additions. We’ll continue to carry out that program up to a 120 Bcf at Pine Prairie and Southern Pines and we’re positioned for complimentary strategic opportunities.
Intermediate long-term three years to five years out, we see the improvement in the spreads for all the reasons I talked about they are all listed here, and in addition you could have the potential for NGVs rail run by natural gas. All these things that aren’t even baked into this as natural gas comes on and takes some more row with supply being there, and certainty of it, all paints a very different landscape than what we’re living in today. On the positioning side for us, strategically located assets commercial and operational flexibility we can -- we have those, the group, the talent and the certainly a committed sponsor in PAA.
So, as an investor was a consideration. Take a look at the attributes and we’ll pound one more time. Assets in the right place, low cost expansion capabilities. We are making a nice return in this environment, give us a little bit of headwind a little bit of market, it’s even going to look better. Solid fee based contract profile. I think that’s critical particularly through these next few years. We’ve got the team that can capitalize on the opportunities that the market shows us today. I mean if we didn’t have that in place we couldn’t put the results on the Board that we do right now, very critical. Market doesn’t show you much, but when it shows itself, you got to be able to capture it and we’ve certainly been able to do that. And then well within our targeted credit and liquidity metrics and again, can’t say enough about our sponsor in PAA.
So what does PNG provide investors? You got a option on recovery growth in the natural gas market, near-term option on event-driven acquisitions and market opportunities that occur. And then down at the bottom a solid distribution whether it’s 6.5%, 7% yield, nice tax shield while you wait. Not too many investments I think can show you all those things at least in this market with the upside that you could get as we see the market changing in the next few years.
So, with that, I’ll ask Ben to come up and we’ll do some Q&A.
Any questions? Can’t forget about our sponsors.
Good afternoon. I wondered if you could talk a little bit about the average, the roll-off of the contracts that were signed back when energy prices were higher, or natural gas prices were higher, and when that impact of the roll-offs is going to basically flatten out or disappear?
Ben you want to take that?
Well, in general, we contract typically for a three-year time period. And so contracts that we have rolling off near-term would be in that same time period. We do have some longer-term contracts, but we’ve already seen the effect of that in the last couple of years. We had some longer-term contracts that rolled off and we’ve replaced those. So I don’t see anything different than what we have in our current outlook on roll-offs. There’s not a big cliff out there or anything of roll-off contracts coming into play.
Yeah, I’m going to just add. I think as a practice, when we went public, I think substantially all those contracts material portion of them have either rolled off or been included in our guidance going forward. The exception to that I think Ben referenced to is when we bought Southern Pines, we acquired some contracts that had 10 year contracts and some of those just started when we hit certain performance benchmarks of putting storage in service. So, those probably have eight years or nine years left on them. So I don’t think you’ll see those coming into play in anytime in the very near-term. There may still be a few contracts at some of the higher levels that may roll-off in the next couple of years, but as a percentage of the total it’s just not that much.
Yeah to add on to what Greg said interestingly enough, now some of the recent contracts we’ve signed at Bluewater not only been with logistics type customers, they’ve been in kind of the five-year nature versus three.
Could you flush out a little bit more what the actual gas pipeline capacity that you showed a minute ago, what’s the actual amount that’s going to come offline? And could you just talk a little bit more about how’s that going to tighten, or excuse me, widen any differentials for you a little bit. I mean we’re producing, unlike five years ago or producing 2Bs a day 90 miles from here, right in Susquehanna County. So if you could just explain that a little bit more, I don’t quite understand how that’s going to work? Thank you.
Okay. If you look at the grid right now and how’s it set up, what’s happening and you’ve got excess capacity, and I’ll kind of go through some of the changes that have been announced. You’ve got trunk line taking their line that just completely out of net gas service. You couple that with Board walks announcement, just taking one of their Texas gas lines, they still have two to serve that gas, but it takes out cushion out of the thing, that’s about 600 or 0.6 a day, just those two announcements right there. Take CGT that traditionally flowed two with their three pipes 2Bs a day from Gulf Coast to Northeast, start to change the dynamics around. They’ve already announced it. They are switching that line around. It is coming from the Marcellus because you have excess capacity out there down to Gulf Coast to Henry Hub.
What that does when you change that even the 0.5 B, overtime it has impact. I think as the market grows and you see, it’s in response to what’s happening down here or what’s projected to happen. As you see the LNG market grow, you’re going to need more gas to serve it. That in tail will change I think the bases differential from where it is now Marcellus to the Gulf Coast. It’s non-existent today, anything is a plus, and I think you’re going to see some of that change. So, I don’t know if I answered your question but those little tweaks right there to the system, not only do they do that but they take what I’d just call excess infrastructure, change the direction of some of it and some of it just take it off the Board, that helps storage because then you need storage really to balance the equation even in a fairly strong supply market.
You’ve already seen some of it today, just weather driven events, but when you add, let’s just call it 20% to the current per day average, it’s going to be a change in the market particularly when you start changing the flows and the directions. And no different kind of in reverse in what we saw when the three or four big 42-inch lines were built from East Texas or Louisiana over to Transco 85, just took a little robust differential or bases differential to nothing. I think you’re going to start to see those type of changes.
You mean in the reverse Dean, right?
Next question over here.
Could you please comment, do you expect the pricing improvement to come primarily from summer/winter spreads widening out, or do you think that the actual pricing structure may change and there will be other fees or other mechanisms to incent potentially more capacity to come online?
Yeah, that’s a good question. When you look at these and I should have covered it in my slides, but when you look at the type of customers that are coming on Power gen customers, industrial base customers, LNG type customers, these are logistics type customers that really even today, are customers in our portfolio. They are not concerned about spreads or orbs or volatility. They want the gas, they need the storage, they only get penalized when they don’t run. So total different set of economics, we see that today.
Not all our contracts are based on those type of market conditions and actually we’ve improved that mix of customers. I think that that’s part of the performance that we’ve been able to show even in this market environment. The nice thing about what we see going forward is the type of customers that are coming on, these are logistics type customers. I think where you are going to see, or will see the pop is in hub services activities to be veiling those type of things. And for those who want the high return service, there is a premium and then you add the market right on top of your facility and it doesn’t take much. Now talking about recovering all the way back to the 60% we lost, we don’t have to do that, get us into what I’d call the low double-digit scenario, we’ll do fine.
Yeah, I may just point out, we just invading elaborate, there are premium prices or ancillary values that you can derive and then we just added no notice service at the Pine Prairie for an electric generating plant and we got a fairly nice pop for that in terms of once they call upon that, you’re going to get more and more service so the actual usage of it. And I think what Dean’s characterized in terms of the shift from the customer mix, from more financial players that were trying to play the orbs to the fundamental logistics players is the same reason that why Cushing were somewhat saying went about the potential for over billed because at the end of the day our facility set up in Cushing, to basically deliver services that other people can’t do.
Same thing is true at Pine Prairie. I think if you look at compression per Mcf of storage capacity, there is only a few of us that actually can deliver all the services that they would sell at everybody shows up at one time. And so I think at the end of day, they are going to pay a premium, if they are calling you have to say I need gas to generate electricity because it’s very, very hot, you better be able to provide that service, they don’t want to hear we don’t have it today.
Just want to review the reasons for spinning this out as a separate company what they were and so that how you view that, those reasons now?
Al, I’d take that one.
As Dean mentioned, and he took my…
Unidentified Company Representative
It was a jump off, I figured you jump higher than the other guys.
He took my subtitle off the slide which was – the question was subtitles why does PAA if PNG exists on the background. And the reason quite clearly there was we had such visibility of growth organically. At the time we went public we shaved our forecast 10% of the rates we were signing at the time, we actually signed rates 10% higher or even after we finished public offering, kind of under promise over performed approach. And so we felt like we had an extremely well established growth pattern from organic, and we also figured out that there were several project development coming out there because we though we’re going to struggle to execute, they may had the same the right market same when we did the, we thought they had true to execute.
So we wanted to create a currency that will allow us to exchange like-for-like clearly as PNG 6% of PAA, if they wanted to exchange for PAA units, they will be trading from a natural gas investment to a crude oil investment. As Dean’s slides suggested we misread the market over the impact of the Shale gas and we also misread the timing. We would not try to do an opio at the peak and not planning to get completely out it, it was just really trying to create a currency. So that cost of capital we expected to be less than PAA. Today even though the yield spread is between 4% on PAA and call 6.5 to 7% on PNG, the actual cost of equity capital because of the visibility of growth that PAA is actually a little bit tighter than you would actually think.
And back that the Dean’s comment not so much tongue and cheek as reality as we think that there is a lot of projects out there that still need to be consolidated that probably because the way they are set up sponsor wise need to continue their investment in the natural gas sector. So having a total currency out there that you like still has a lot of attractiveness. Clearly even though we can hold our breath longer than everybody else, we can’t hold it forever. But we certainly got plenty of fire power in the tank with respect to the three to five year horizon out there. And there is lot of value in having that as a separate entity from PAA’s perspective. If we can generate the kind of growth through consolidation and continued expansion the value of the GP ownership which is 100% held by PAA takes on the higher multiple than you could attract anywhere else.
Is there any capacity right now remind me I can’t remember if that PNG has contracted to PAA, and what is the appetite for PAA to take on additional capacity in the future to potentially warehouse optimization opportunities?
Additional to the 20 Bcf that we talked about is that what you are asking about?
We don’t have any plans to treats for anymore capacity, but I think we outlined when we first rolled out the fact that we had contracted 20 Bcf with PAA, that the purpose of that was, to smooth out their earnings for PNG and to ride the lower cost way of monetizing their capacity. It will be clear that when we contracted that 20 Bcf to PAA, part of the concept was there that we feel that we could hit those values that we contracted for and feel that way today that we can continue to perform on that.
Unidentified Company Representative
It really down to if you look at, if you’re holding 20 Bcf, imagine trying or having the friction or the trying to settle that all in December at year-end versus the flexibility of spreading it out and doing it at the best time the market has to offer, whether that’s been January, February or March. That’s the flexibility it gave PNG smoothing things out has been talked about, and the upside of taking that friction cost up trying to land 20 Bs in December which you can do, but you’re going to give up some and that go into PAA.
It allowed us to basically provide the certainty to PNG from PAA standpoint, we were going to make a profit on our investment, we might not make it in the calendar year ’12 but some of these opportunities over a 24-month period very confident that you’re going to get those opportunities just as in any given 12-months. We like to hit our guidance and it was a little bit uncomfortable to have PNG have to turn around slightly, if I close this position out which is a buy sell in January of next year, I already miss my guidance this year, because it just shows the earnings into the next year. So – have those headaches, it was really a way to add certainty, the point of time when we did have some contracts rolling off, it was kind of the hump year for the contract roll off, so we did it at very close to about slightly premium to market to make sure that we sanitize the transaction, but it added certainly at PNG if it had retained value of the PAA organization.
You have another question here in the front.
Just a question, I mean given the original strategy was to create a currency in PNG units and now that you have a substantial yield differential between the two, do you look at acquiring potential properties in PAA and just drop it down to PNG, basically reverse the strategy given where things are trading today and then, I mean is that something you look at?
It is certainly one of the tools in a tool chest, some of the opportunities out there not limited to storage but we would view this as opportunity for our gas platform. So it’s been very difficult in the past when the gas business was so hot to buy any natural gas pipeline, it’s a little bit more less robust let’s say today because it’s a really a challenging industry. So to buy interstate pipeline or any pipeline would be an exciting opportunity for PNG to extend it would be pumped in and in compliment what we are doing there. And so the idea of slowing those have had an immature stage and not yet right for PNG wherever things very material, the potential to warehouse something that PAA and then drop it down either in pieces over time, certainly something that we would look to do. I mean we are trying to make the best return for the whole organization and honor it at the same time, the – the commitments we make, the individual investors and I think we’ve done a good job at PAA of taking the right steps at the right time to make sure that we maintain the integrity of the whole process and our commitment to the public to always do our best to deliver the value.
We have time for one more question at PNG, if there is a question.
Are you in a position to give us an idea of returns, are you in a position to give us an idea of return on capital on the newer contracts you are signing?
I’m sorry, I couldn’t hint the question?
Unidentified Company Representative
The rates on the new contracts we’re signing?
He is just asking for return on capital on kind of the new contracts, I think he might give talk about new additions and expansions. Are you talking about the rate of return on capital on…
Your signing in the last three months.
Unidentified Company Representative
Well, I mean the rate of return is on the investments we’re making as far as the storage expansion and they are in the low to mid teens in terms of return on the capital expansion. As far as if you are talking about the lease that we’ve been signing between PAA and PNG those are public and it was $0.75 for the two year and $0.85 for the three year contract. But the answer on the expansions that we’re making which are very attractive, within the low to mid teens, that the reason you’re not seeing the robust growth on the top line or at the bottom line is because it’s been all set by the contracts, erosion of the contracts rolling off which is if you think about it, we’ve had about 60% plus erosion in the market since 2010. If you only had a 20% increase from current levels, you’d still only be down net 50% but be up 20% over the current level. So it won’t know how much larger volume I think we had 40, 50 Bcf, now we’ve given 120. So when we see a recovery I think the important thing Dean mentioned it is if you are patient and you are getting paid the way, if you see a recovery in rates it can be geometric in terms of its impact on the bottom line.
Thank you Dean.
Alright. Good afternoon. Home stretch I think we can see the finish line here so… I’m going to just really touch on financial growth strategy, capitalization, debt maturities and also investment considerations. For those of you who have covered us and reviewed us for a while, you won’t see a whole lot of change in this slide. We believe our financial growth strategy has been at critical part of kind of the overall growth and strong performance of the partnership over the last decade in essence. First tenant of it is really to fund our growth with approved amount of equity, 55% equity or retained cash flow.
We do focus very intently on trying to minimize capital market risk. We will prefund or refund our capital frequently. I’m going to walk through some of that in the next slides. We target a credit profile that we think is commensurate with BBB+ BAA1 credit rating. That is our goal is to achieve and maintain those credit ratings. Today we are BBB flat BAA2. Also focus very intently on our liquidity to maintain strong liquidity and to manage kind of the risk of the debt portfolio being interest rate exposure and debt maturity profile. It’s pretty easy to kind of lay that out and talk through financial growth strategy. I think only the harder part is to actually deliver on it and what’s really hard is to deliver on a consistently over a long period of time.
We think we’ve done that. The next few slides, I’m going to kind of walk through pretty quickly but try to illustrate how we think we’ve delivered on this strategy over long period of time. clearly we think the execution on the financial side is kind of second to none in amongst our large capital investment grade peer group. This first slide really shows a little over $8 billion of capital investment over the last five years in essence our target 55% we funded 63% over this period or will be or including 2013 in our numbers. Through that maintain very strong coverage 136% and clearly when you look at some of the bars you can tell the early in pre funding.
We clearly were in prefatory mode in 2011 with a view of having some opportunities in 2012 including some of the acquisitions we closed the BP NGL acquisition as an example. This slide really takes the cut from a different angle, it looks that capitalization, the bars are of good capitalization over roughly a decade period. Same chart on either side and then you see long term debt to capital metric in long term debt to adjusted EBITDA. We invested over $14 billion during this period and it never really got ever outside of our credit metrics again demonstrating our performance of issuing equity or retaining cash flow either at the time we needed it or before the time we actually needed it.
What you can tell when you look at the right hand panel, the last several years kind of the key credit metric the long term debt to adjusted EBITDA really retaining and staying below the bottom end of our target range. That in essence is somewhat driven by the strong fundamentals, but it’s also have been driven by the equity prefunding that we’ve been doing and to retain cash flow. Clearly cut the same type of data, this is about 3.5 year period that the same conclusions when you look at it. If you slice or dice it basically anytime over that decade period, we’ve delivered against the strategy of making sure we keep our balance sheet in line.
The other objective I mentioned was to achieve BBB+ BAA1 credit rating. What we’ve done here is taken some of the key credit metrics and compared ourselves against the peer group. This peer group will be BBB flat or BBB+ equivalent. Peers it doesn’t include the BBB- and in effect what you can see is we think the credit profile of the partnership is commensurate with the upgrade to BBB+ BAA1. We think the commitment to it is strong and ultimately we believe in time that it will occur. The next kind of one key tenant of the strategy was liquidity. What this chart shows is, the red shows kind of the high and low quarter end liquidities over a six year period, the green line is kind of the average and in effect we’ve maintained very strong liquidity.
One through early part being the financial crises and recession in more or late just through where we see significant opportunity for potential growth. Our view one liquidity is kind of twofold one from a defensive standpoint clearly having strong liquidity when the markets are in turmoil provides a degree of comfort. Secondly, during times of strong investment opportunities we think there is an offense of attribute to it as well. Example in late 2011 as we signed the BP NGL acquisition and a couple of other deals for over $2 billion, we didn’t have to really worry about having the liquidity to execute those opportunities plus our growth programs.
The other couple tenants of the strategy around maturity profile and interest rate floating fixed mix and then what you can tell here is 12 year average maturity of our debt profile, highly fixed. We think being highly fixed especially when you are issuing it at the rates we’ve been issuing in last few years makes a lot of sense, it provides a lot of protection for our unit holders in our DCF coverage, and again you see very few maturities over the next several years. This chart really then kind of wraps up the capital structure and that side of it again. Well within our targets as of March 31st very strong, leverage of less than three times on a adjusted debt to EBITDA metric and very strong liquidity.
I’m going to shift gears now kind of touch a little bit on segment for – segment results, some of the growth there fee based mix et cetera. I’ll just touch a little bit on the segments; I think you got a good flavor for what assets are embedded in those segments from the earlier parts of the presentation. But we have two fee based segments, transportation facilities; you see kind of the assets used in those segments denoted there. Supply and Logistics on the top, there is clearly a lot of discussion about that earlier, in essence that’s where we yield buy product take tile move it to the market and resell it. We use our logistics assets embedded in that, trucks and rail cars, but we also have a substantial amount of line fill, very significant investment in that embedded in that segment as well. When we do these activities we don’t take price risk, so we’ll buy on floating indices and sell on floating indices. I think you heard Harry kind of describe it is a margin based business.
When you look at kind of the growth of the company over a number of years, what you’ve seen of late is strong growth in our fee-based segments and that’s really a function of the capital investments that you’ve heard a lot about today, acquisitions organic growth and we expect that to continue, I’ll touch a little bit on that. What you’ve also seen is very strong results in our supply and logistics segment, as you can tell 2012, 855 million of segment profit. I will touch a little bit on our second half guidance and kind of in approach that Greg discussed earlier of a base line forecast. Again we do think we’ll have opportunities above that, but that’s the approach we use for forecasting.
When you look at the transportation segment, in essence the bars show volumes throughput volumes, the line would be unit margins, in the kind of the blue numbers on the top show kind of segment profit and again what you’re seeing is growing volumes improving unit margins, so growing segment profit from the area, or from the segment excuse me. What’s driving the volumes today is all the areas that you heard early in the presentation, Permian, Eagle Ford, Mid-Continent areas are areas where we are investing capital. Some of those projects will have it will take several years for the pipes to totally fill up, so we see continued growth as we look out over the next few years.
Most of our tenants in these pipeline systems have escalators in them. So there is nice inflation protection as you look out over time, again part of the improving unit margins. When you look at the segment, roughly about two thirds of our current capital program is being deployed in to it. And when you looked at the portfolio numbers, there are substantial amount of what we think our future capital that is part of the portfolio will go to the segment. Again it will drive an increase in segment profit over the next number of years from the transportation segment. Facility segment similar, what you see here is the bars represent capacity, monthly capacity.
Red line shows the unit margins and the blue being the segment profit. Again clearly recent growth from this segment is the BP, primarily the BP NGL transaction as well as the USD rail acquisition and some growth in our crude terminals, construction of terminals that you heard about Cushing being one example. This year part of what’s driving some of the growth is again USD having a full year that would close on that acquisition in December of last year. Roughly about a third of our current capitals going into the facility segment, and again we expect to see continued growth in contribution from this segment as we look out based on again the investments and as we fully integrate the BP NGL transaction that Dave discussed earlier.
Supply and Logistics, the format of the slide is very similar other than I put a dotted dash line on the right hand side to kind of show also a second half annualized number, but in essence here what you see is the green is volumes, you see a lot of growth in those volumes starting 2011 going across, that’s part of the crude oil development that you have heard a lot about from the resource plays or big – of those volumes have been growing commensurate with the growth in North American in oil supply. We expect that to continue over a number of years as Greg kind of walk through in his segment, as well as the BP NGL acquisition, the growth in our NGL throughput volumes from that acquisition as well.
What you see is you see a very significant growth in per unit margins due to some of the constraints in infrastructure that we’ve discussed, again peaking at the $2.33 in 2012. Current mid-point guidance for this year is it’s showing that coming down to a $1.87. What you see is second half annualized at a $1.14 kind of a reversion to a base line. Again that’s how we forecast as Greg mentioned we do expect over a 12 to 18-month period to see opportunities above the base line, we just can’t forecast necessarily when those will occur. What we do believe is that we will see continued growth in base line cash flow from this segment, based on just the oil supply growth in North America, U.S. and Canada.
When you kind of take all that and think about one of the key metrics of the rating agencies look at as well some of our bond investors is kind of percent. I think we had a question earlier in the day on a 2% fee base, when you look at this what you see is if you look kind of in the very left side take 2010 roughly at 75-25 mix. What you see is those mix got shifted a lot by supply and logistics growth in essence the 2012 it was 59-41%. If you think about the right inside up on the top, effectively what we are seeing is a very strong growth in our fee based segments, it’s just very strong results in supply and logistics created a temporary shift in the percentages. We expect that to normalize.
Second half annualized or second half percentages there shows kind of back to where it was in 2010, 76-24. As we continue to make the investments in the segments, transportation facility segments in essence roughly 100%, almost a 100% of that capital goes into these other segments creating new pipelines, new terminals. We expect to migrate closer towards the 80-20 over the next several years. I’ll shift gears a little bit, talk about DCF and retain cash clearly a key part of what’s been part of our financing strategy, the last several years. In essence what you see here on the kind of the bar chart, green being cash we distributed, yellow being cash we retained. As Harry touched on we retained that, we invested back into our transportation facility segment.
Pie chart shows kind of a roughly one quarter, three quarters cash flow split over the last nine years, so we’ve retained just under $2 billion over the period. This is our lowest cost form of equity capital. We do think that produces a meaningful benefit over the long term to our limited partners. In the next couple of slides I have just kind of walk through a little bit of that to illustrate that. This chart shows the mask behind the two right bars, basically our guidance for this year and 2012. You see the 160% coverage and 135% coverage. In essence when you look at it over these two years, we will have retained approximately $1 billion of cash flow and not distributed it. If you look at what that means is we have avoided having the issue roughly 21 million units, LP units. The current cost to service 21 million units would have been about $71 million.
When you look at how that would have affected our distribution capacity, it would equate to about $0.10 or roughly 5% of our current distribution. So fairly meaningful benefit out of our ability to retain cash, especially during some of these temporary market conditions and to reinvest back into our business. The other key part of our equity kind of raising strategies, the last year, a little over year has been our continuous equity offering program. Program we think has proven extremely successful. It’s significantly lower cost for us, roughly 80% lower cost in a kind of a traditional overnight offerings between the fee and the discount to market.
We think it’s very beneficial by avoiding disruption to kind of unit trading patterns that type of things. We implemented in May of ’12 and through the first quarter of this year a little less than one year period we had raised 655 million through this program. So we think we did that without really having a material or even a meaningful impact on our unit trading price. And so we think it’s a very effective way for us to raise capital, it works much better if you are ahead of the curve or you are able to kind of raise in small increments and be selective on which days you do it. So if unit to price trade down you choose not to raise any of that particular day. And so we found it to be a very effective program.
When we look ahead kind of our future plans, you heard a lot about our capital portfolio, our programs. We feel very comfortable that we have significant investment opportunities as we look out the next several years in front of us. Harry touched on it. We also expect to continue our disciplined acquisition program. So we think we’ll have a need to continue to raise equity capital. We have a strong balance sheet credit profile, high liquidity. So our future raises will be opportunistic, they will be prefunding 2014-2015 requirements as we look at it. Our current program we re-filed earlier this week, it’s a $750 million program.
Absent of major or significant acquisition we don’t expect to have to access the traditional overnight or marketed equity offering the rest of this year. We do think this will, between this and capital that will retain cash flow will fund our organic programs. Kind of touching on that, we do think that presents kind of a unique view for PAA. In essence what I got here is a little chart just showing of the top 10 sized MLPs, we’re one of three that haven’t had to in the last 12 months go raise equity in overnight transaction, several of them have to had to do it a number of times. Again the last time we did was to fund the $1.7 billion BP transaction in early 2012.
You might wonder why I put this slide in here, if we don’t have to access the market, when we have in essence to take away has been we’ve done 26 equity offerings in the partnerships’ history, most of them near our 52-week high and the returns are very strong. So if we do have to come to the market because of an opportunity again we think the returns speak for themselves relative to the group. My final slide and I usually describe this slide as kind of a report card because I normally come towards the end of the presentation and in essence what you’ve heard about is as our business strategy, our assets, our positioning in a lot of basins that type of things. And this really kind of shows a little bit of historical results, historical performance both operationally and financially.
We’ve delivered very strong growth, adjusted EBITDA by 28% compound, 7.7% distribution growth. Distribution growth last several years has actually accelerated even as we are a much larger entity. Very strong returns relative to the group, the AMZ Group as well as the broader markets. Again, we feel very well positioned as we look ahead as well. And with that I think we are now in the final stretch for sure.
Don’t show the smile. This is our impressive turn out, -- record it. As Al said we’re almost done, there are a few important patterns that I do want to touch based on before we close and open it up for final questions. The first is really our commitment to operational excellence and that’s certainly in the areas of safety, pipeline integrity management and incident response preparation. Also want to touch base on our management team, our ability to develop, retain and long-term succession planning and close to some concluding thoughts.
With respect to operational excellence especially in the area of safety, it’s an area that we are never satisfied, we’re certainly pleased that our statistics show that our is the rate of superior to the industry average, but we are constantly looking to improve and our goal would be zero incidents while not practical, it certainly something that we think philosophically we should be striving for. As the slide indicates, we’ve had a really good record in last four years and now the 10 years we have been obviously proper side of the industry average. Our trucking group significant increase in the total miles that they have travelled. You can see them 2001 it was almost 32 million miles and in 2012 84 million miles.
We are in addition of moving energy products for the use of others we tend to use quite a bit ourselves. But again there a very superior recordable incident rate for the last 10 years. And then another measure just our performance in that area is that over a 10-year trend we’ve had fewer workers compensation claims than the industry average. While at the same time increase in our employee headcount from 1,200 to 4,700. With respect to integrity management, this is an area that we again put a lot of focus on, we’re never satisfied but we are pleased with the progress that we are making and we think the industry is making. But we are committed to clearly maintaining our assets for the long-term. We are business builders, we’re not here to manage for next year, we’re here to manage for the next 20 years.
And we continue to have numerous programs that really go well beyond the regulatory requirements that are placed upon us, so we are using the new technologies to identify areas requiring attention, includes everything for the most latest developments and smart pigs, advanced data interpretation. We’re also improving our ability to take us there and integrate it into composites that help us to power tasks, our activities focusing on and assess the areas wanting attention. We’ve also established multiple programs to mitigate any damage to the environment, one is horizontal directional drilling, used to use simply laid a pipeline across the river, cover it up and hope that you are a couple of feet below the surface. In many cases we are dealing, we call HDDs, our horizontal directional drilling where we’re drilling underneath the river in some cases 30 and 40 feet below that so that we don’t have any car – as the flooding happens, it’s not going to expose our pipelines.
In areas where we haven’t quite got at that point, we’ve taken a very proactive step to precautionary shut ins as we see high water levels increase, even though we may not have any exposed pipe there, we’re just worried about what could happen. That certainly hurts our performance in a given quarter and it incurs expenses, but we think is the prudent thing to do for the long term we’re trying to get better and better every time we turn around to try and figure out ways to mitigate potential exposure. And then we’re also installing automated block values in much higher concentrations in and around areas that we think are exposed to, if there were an incident that it could have some running room before we could actually get to the shut off valves. Since 2007 including our capital we’ll spend this year and expenses, we spent $1 billion in maintenance capital and expense. On integrity management, the API 653 repairs et cetera that includes about 215 million that’s hitting us in 2013. We also want to make sure we’re always prepared for one incident. Again our goal would be zero incidents but this is not a perfect world and as hard as we try, we can’t attain perfection either but we’re certainly always trying.
But basically we try to make sure we engage in a program of effective planning and training on an ongoing basis, regularly engaging with our first responders across the company, we have a lot of incident management tools and resources ready for use and we empower our employees to act consistent with our culture. We try to foster culture that emphasizes operational excellence, asset integrity and employee and public safety. In the unfortunate event of an incident, we will be prepared. Our key objective is to preserve life and safeguard the environment through the immediate response and deployment of resources. Our PAA resource personnel have unrestricted authority to take whatever actions are necessary to accomplish those objectives, and let me re-emphasize that again. The lowest kind of – poll out there, before we can get anybody else has the authority to pull the trigger to go spin what’s necessary to try and accomplish those objectives. We do not want delays or bureaucratic hold ups to endanger those objectives.
Next item on the closing list here is PAA management team. It’s clearly been a critical part of our success to date and we think it’s going to continue to be a key element of our ongoing success. I think the presenters that you’re seeing today are just illustrative of the quality, experience, talent and the commitment of the entire management team. We have over 40 members in our senior management team that have a collective experience of over 1,100 years spread across upstream, midstream and downstream. The highest concentration clearly is in the midstream but it’s important to know we’ve got experience on both sides of that. The average age is 51. Many of us have worked together for over 10 years and in some cases well over 25, in other cases well over 30. We’re the ones pulling the average up to 51.
In that regard, we are committed to an organizational development, retention, succession planning. We have a very rigorous emergency succession plan that’s been put in place that’s reviewed every year at least once a year with the Board so that we know what would happen in case there was an event. We always referred to it as getting hit by a bus. I try to avoid buses in all cases. But and we’ve also got a targeted leadership development program. We’re trying to basically take the steps necessary to make sure that what we’ve accomplished and what we think we can accomplish has continued for many, many years. We do focus on employee retention. Our non-driver turnover rates, driver turnover rates are fairly high but if you exclude that it’s about 9% per year, that compares to our industry average from our peers of about 10%. And if you look at the Fortune’s 100 most basically best companies to work for, their retention rate is 14%. So we think that 9% higher than we wanted to be, it’s certainly very, very attractive relative to the competition.
We do structure our compensation programs, our bonus and equity compensation to reward performance both for the achievement of annual goals as well as long-term distribution growth which is clearly aligned with the best interest of our unit holders and we also have extended overlapping minimum service periods. So even though you may have achieved the performance benchmarks, in most cases, our awards are best over 3, 4, 5 year period, they happen every roughly three years so that you’re always having a lot at risk if you choose to lead. Even though you hit the performance benchmark, if you lead, you’re going to leave that behind. If we let you go you’re protected so that you understand that you’ve been rewarded for what you’ve achieved. But it’s really trying to make sure that we retain people and I think that certainly contributes to our attractive retention rate.
So, in kind of wrapping everything up today, I just want to kind of a few comments. Looking forward, hopefully you can see we’re very optimistic about PAA’s future. We think the North American crude oil industry and gulf fundamentals remain very favorable. We have a very strong asset footprint in substantially all of the crude oil growth areas in North America. Cycle tested business model. We’ve got a proven management team and we’ve got strong visibility for continued and attractive distribution growth underpinned by our recent investments in our ongoing growth portfolios. We delivered 9% growth in 2012. We’re on track to deliver our goal of 9% to 10% growth in 2013. And as Mark and Dave and Harry mentioned, a lot of the capital that we invested in the last couple of years you saw that significant ramp up in the capital investment activities in last several years, we’re really just now starting to harvest. So we think we’ve got a lot of momentum in the system. Even if we shut down spending tomorrow, we would still have a tremendous amount of growth in our operating performance which will translate into distribution growth. So we’re feeling very good about the near-term and intermediate-term visibility and feel pretty positive about the long-term based upon the trends that we see.
Harry said that, mentioned earlier that some of us are pooling average up above up to 51. I’ve been in the business for the long time and we – this is a very humbling business. Conditions in the energy sector can and will change very rapidly despite the best planning. If we were having this discussion seven years ago, everybody remembers gas was the way with a future and we were going to be export or excuse me, importing a tremendous amount of LNG and re-gasifying it because we were running out now we’re going the other direction and that happened just in really a very short period of time. So we’re not naïve in understanding that things can change in the crude oil business. And as a result of that, we’re always kind of looking over our shoulder and the good news is that as we’ve proven, as Roy showed you in a slide at very beginning, we generated and exceeded our guidance in periods where we had declining production, increasing production, declining consumptions, increasing consumption and a significant amount of volatility in both market structure differentials and out right price.
So we think we’re very well positioned to continue to do it in almost any environment. We kind of lacked the one that we’ve drawn forward and hopefully continue to see that as we move forward. This is the suggested takeaway points. I won’t repeat them. This is just a repeat of the slide that you had earlier. The other thing is for those that slot during part of the presentation and you need to file a report but next four slides, I’m not going to go through in detail. This is a summary of the highlights that if you were taking those, we think this is what you should have written down. But again we’re looking for robust growth in crude oil volumes, in NGL, very well positioned in both U.S. and Canada to take advantage of that environment. And the PNG as Dean said it’s a tough environment but we think we’re basically doing as good if not better job than anybody else in the industry and we think that it’s something that you’re getting paid to wait for it to improve when we certainly think it will.
Al did a great job of covering the financial overview and putting our plug in for an upgrade to BBB+, BAA1. We think we should be part of the inaugural class so to speak, they just opened that rating up and so we’re making hard our pitch here today and also tomorrow. And lastly on distribution growth. We’re just well positioned to continue to deliver strong and attractive distribution growth. Not only do we have high coverage but we have a lot of momentum from the investments that have been made on the fee-based side of it which are going to drive about the baseline level and enables to generate distribution growth going forward.
So with that, on behalf of our Board, the management team and employees, we certainly want to thank you for the trust you placed in investing with PAA. I think we have one more Q&A session. And then just real ask the number of questions you asked is going to keep us from the cocktail hour, so.
Who’s the brave soul?
I have a question about the continuous stock offerings. And you say that you saved about 80% of the costs. And is that based on strictly the not having the discount and also not having the pay that you repay as fall three types? Or are you also taking into account the other effects because I’m concerned that when you’re selling early, you’re obviously giving up your return on equity, you’re paying a dividend, your distribution on that and wondering if in fact it could be costing you more over the long run by raising your money well before you need it?
The 80% was the calculation versus our true cash costs today of issuing under the program. And what we would so if we were issuing at the same time, under the other program. So a combination of discount to market and lower fees. In essence, the timing of the carry cost to equity is a secondary question. In essence here, we’re choosing to do that and have been choosing to pre-fund equity to be ready for a number of year long ahead of that. we didn’t attempt to put that in there into that particular reference. What we would say is we believe the equity we’ve raised today has not affected the LP distribution that we’ve been having to pay.
Yeah I would just also just, so the math is in a simplified format. If you’re going to go out and do an overnight or market offering, your friction costs, a combination of what would you pay the rapacious investment bankers is a couple of percent. And then you’re looking at a market discount and then you’re some friction costs in there. So it’s about 5% to 6%. Cost us about 1% here. So on what we raised roughly 615 million, take 4% saving and that’s $130 million, okay. So if you think about the carry on that equity is more than offset by the cost if you don’t pre-fund it for more than a year in advance, if you’re inside of a year, it’s actually a positive impact there. The other side of it is not waiting until you need them. Generally speaking when the best opportunities show up, when the capital markets aren’t open and people have to sell and now you’re having to go out and raise higher cost capital to take advantage of a transaction. So what we’ve done is with the visibility that we have of our capital program on our belief it will continue to active in acquisitions. We really think we’re not pre-funding two years ahead of a time, we probably are funding six months to a year and just the savings on the friction costs alone more than covers the cost of the carry there.
I’ll try, I’ll try. Relax, relax. Just trying to hit – you had a little bit as far as debt. I mean we’re probably passed a bottom of the debt cycle at this time. And looking at, when it comes time to get, I know you guys already started doing it. How do you feel, what’s your thought process and thinking regarding may be paying up 100 or 150 basis points to get 20 year, 30 year paper versus 10 year paper?
Well if you look at that profile chart and our recent deal as an example in December, we issued 10s and 30s. There is a 130 to 150 basis points carry but we think it’s prudent to look at using some of the 30-year maturity to extend it. We have done that. We’ve now got four tranches out there and we will continue to look at it at a period of time in the future, you may want to re-visit that. But now clearly the 30-year market generally isn’t as deep but we do like the 30-year rates. Today, we don’t have a need to access the debt markets but we have and will continue to look at extending that maturity.
I think the last two debt deals we did, we did a split tranche 10s and 30s. And our bias was we’d like to find out just how deep the 30-year market was without pushing the price round and that’s pretty much what we do. We took pretty much the total amount that let us take without changing the price. It’s just – we need time you can issue 30-year debt with a fore handle in front of it. I just can’t imagine when you’re going to regret that. It’s clearly costing the short-term and for companies that are having trouble covering their distribution one-to-one, that 150 basis points can be pretty meaningful. Part of the benefit of being ahead of the curve is all set on financing and on distribution coverage is you have that luxury of making the right decision as opposed to what may be the near-term or long-term decision.
I have a question Greg. You just wanted a PTP and I think there was a lot of talk about the asset class in sort of comparing it to reach, what I think there are some institutions in raising money to go into MLP. Maybe talk about mid-term to long-term what you think the broader MLP asset class evolution looks like.
Well we’ve been real pleased with becoming from primarily a retail product to more of an institutional product. MLPs are still more complex than reads in terms of – because of the reporting and there is other passive active income component there. But we’re getting the best traction about now is word of mouth. People that have had success, talk to other success that want success about investing in there, and they finally get their mind wrapped around the fact that this is an asset class, is generally speaking a high returning asset on a cash basis plus growth plus a relatively low risk, that’s not to say all MLPs within there is roughly 350 billion. I think a market cap now, much MLPs around 90 MLPs that’s not quite the same size as the read, I think the read class is probably in the 600 million, 700 million range. If you include though, not only the MLPs but those that have a publicly traded general partner may be in Seacorp and you put that in there, in general you’re talking about where there about the same at the re-class, I think on a performance wise, I’m much rather on MLPs than reads because on read basis clearly you can have regional depressions as opposed to our asset base that’s spared across the entire United States. So I think overtime we’re going to continue to gain own reads and hopefully pass them. This is my opinion.
Other questions? Before the break, there was one question that was answered earlier but I think there might have been a little bit of confusion on or the answer might have found a little bit confusing. It had to do with slide 55 which is related to the Permian Basin takeaway capacity and the basin pipeline and Greg, if you want to clear that?
Yeah I think John Towson asked the question whether or not our ability preserve our profitability on Mason basin included or excluded the impact of Cactus and I think we may have two or three ways to interpret it, what I thought we heard. But Cactus is a standalone, new capital being spent generating a great return on it. And it has no influence on our ability to retain the cash flow that we have other than the fact that the directional flow of the crude volumes will help that but we’re not spending money over here to try and retain cash flow over here. We’re spending money on Cactus to basically generate incremental cash flows. And as a by-product of that, the volume flows that we’ll see across the basin system will actually help generate additional tariffs on volumes that are going to transfer from one system to another across but basin header system. Harry I think I said that right.
So any other questions? If not, thank you all very, very, very much.
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