Sanjay Lad – Director, IR
Mark Maki – President, Enbridge Energy Management LLC and SVP, Enbridge Energy Company, Inc.
Steve Wuori – President, Liquids Pipelines and Major Projects
John Loiacono – VP, Commercial Activities
Steve Neyland – VP, Finance
Darren Yaworsky – Treasurer
Ted Durbin – Goldman Sachs
Brian Zarahn – Barclays Capital
TJ Schultz – RBC
Winfried Freuhauf – W Fruehauf Consulting Limited
Jody Lurie – Janney
Enbridge Energy Partners LP (EEP) 2013 Investment Community Conference Call March 6, 2013 9:00 AM ET
Good morning. Good morning and welcome to the Annual Investment Community Conference for Enbridge Energy Partners. My name is Sanjay Lad and I’m the Director of Investor Relations for the partnership.
In the spirit of safety, let’s start with a brief safety moment. In the event of a fire, please exit through the back conference doors, proceed down the stairs and there you’ll be met with hotel personnel who would direct you to the street level exit.
As a reminder, this presentation is being webcast. If you have any questions, please wait for the microphone, state your name to identify yourself and your firm so that people listening on the webcast may follow along.
Moving forward to slide 2, this presentation will include forward-looking statements. The risks associated with forward-looking statements have been outlined on the slide and in the partnership’s most recent SEC filings and we incorporate those by reference today.
And with those opening remarks, is my pleasure to introduce Mark Maki, President.
Well, good morning everybody and thank you Sanjay for the introduction. I see there are some open seats up in front, just like the University, everyone is kind of congregated in the back row is packed, even Fletcher and Noah back there. So, but certainly seats up front, there are lots of places to folks that are just coming into the room.
In terms of agenda, you see, on the screen back here, little introduction from me, with respect to just general partnership strategy. And then we’re going to have Steve Wuori get up and talk about Liquids Pipelines Group. We got a break after Steve I know last year we had this. A number of folks took advantage of the opportunity to sit down and have a sidebar with Steve, and that certainly is something for folks to do again this year.
After the break we come back with natural gas, discussion by John Loiacono, then Finance by Steve Neyland and a few closing remarks from me and then we’ll break for lunch so, again very full day. And I’d like to take questions really after each section.
Okay, there we go. In terms of just key messages, one of the things that I want to highlight for you with respect to the partnership is really what our overall message is. And number one, the very first thing that we focused on at Enbridge is safety. Safety is job number one. We’ve talked a lot about it on the last few quarter conference calls, with respect to pipeline integrity expenses and other things we’ve had going on in the company. But that is where it all starts.
So, if we’re able to do a very good job, a leading job, be the number one in the area of pipeline integrity, it will lead to other opportunities for us. And if you look at the amount of capital we’re putting to work over the next five years, being a first-in-class operator is critical. And that will lead to further opportunities for us over the long run.
The second thing I want to emphasize really throughout the presentation is nobody in the MLP space has a set of assets that we do especially with respect to Liquids Pipelines and crude oil asset. We’re hard-wired to the Western Canadian oil sands. We’ve got a dominant position in the Bakken. And then if you look at the market set, our system access is what you look at Minneapolis, St. Paul, Chicago, Detroit, Toledo, Toronto, Sarnia, and then through pipelines owned by the parent down to Cushing and now all the way down to the Gulf Coast. Our system gives a producer, a lot of optionality as they move their barrels but through our system.
The size and scale of our system, no one matches it and because of that you have seen some tremendous growth opportunities come forward over the last 12 months as we look to expand our crude oil systems.
$7.3 billion on the slide, we’ll talk about that more in, and really as what drives our distribution growth outlook in this company. And probably the number one thing that also I want to get across is that growth outlook is also very secure. When you look at the commercial underpinnings of these expansions are typical, utility style cost of service rate making arrangement. Rate based defined, defined rate of return, recovery of capital, return on capital, very stable secure cash flows. And in MLP, that’s great.
Another area we have a very distinct advantage in the area of project execution, we’ve got a very large major project’s group and we’ll talk more about that group a little bit later on in the presentation. But it’s unique skill-set that our company has.
Corporate structure, very familiar, you’ve all seen this before. You’ve got Enbridge Inc up on top, you’ve got some financial metrics on the far right hand side of the chart which I think are interesting. You look at, how we position the different members of the Enbridge family. Enbridge Inc, long track record, since the late 1940s, the company has been around. And great return whether you look at it from inception or the last 10 years, the last five years, the last three years.
And you look at the go forward expectations for the parent double-digit growth in earnings per share, double-digit growth in dividends per share is the expectation. In the family, Enbridge Inc in the growth vehicle and along with that you should get good income in terms of the dividend yield
Enbridge Partners is positioned as more of the stable vehicle in the family, a higher yielding vehicle and because of the MLP structure, you get a tax advantaged yield so, a very effective way if you look at our return over time, again very attractive over the last 10 years.
And of course EEQ is a different way of owning Enbridge Energy Partners rather than getting a K1 and tax area, the tax package that comes along with that, with EEQ your dividend comes in the form of additional shares which you can then cash on when it makes sense for you. And without all the complexities they do come with the partnership investment.
So, you’ve seen this investment thesis from us before, four quadrants yield, stable distributions, lowest business model and strong general partner, I’m going to touch on each of those subjects here in just a minute. This has not changed and this is the way we still run our business to fit within these quadrants.
I’ll talk about Enbridge Inc just for a minute, and the strength of the parent. Very large company, $35 billion equity market cap in excess of $60 billion enterprise value, strong investment grade credit ratings for the debt investors in the room. And as I mentioned earlier industry leading growth in earnings per share and dividends per share, a very uniquely positioned company and a very supportive general partner of the Enbridge Energy Partners.
Over the years, Enbridge Inc, either through direct equity investment in the partnership or partnering up on some of the larger expansions to lighten the financing burden on the partnership has been a very supportive GP. And this is very unique in the MLP space. And the upstream parent has a much bigger half, much bigger balance sheet than the partnership.
So, in terms of where EEP is today, mentioned in our family, in the Enbridge family, EEP is a yield vehicle and currently we’re about 7.8% yield, compared relatively well against peers in terms of being on the higher end of that spectrum. And then our expectations of course will grow about 2% to 5% will grow, our planning horizon which is about five years.
If you look at our returns over time, we’ve done fairly well in the little chart you see in the lower right hand side of the chart. One thing I want to mention is during some very difficult times across, we’ve been around since ‘91 and whether it was the crude oil price declines back in the late 90s or you go to the financial crisis in ‘08 and ‘09, this company has never cut its distribution. We plowed along and we continue to grow. And if you look at returns to investors over time it’s been very attractive.
Now, talk committed about strategic position, I mentioned earlier nobody has the asset platform that this company does. Certainly on the oil side un-rival position where do you look at the Lake Head system which serves all the major refining complexes around the Great Lakes Region. The North Dakota system which is in the premier position in the Bakken, or a mid-continent system which takes oil from the Cushing market up into the Pad 2 markets south of Chicago also a very strong gas asset footprint in Texas, in the Barnett Shale and the Granite Wash in East Texas. And all those regions are being actively developed for rich gas and now some oil exports for Asian in and around those basins as well.
So, asset platform here whether it’s the oil side which is certainly the premier set of assets in the oil space or the gas side, I think one of the best looking GMP platforms in Texas.
Now, I sat here 10 years ago and told you that it was possible that North America would be no longer dependent on imported oil from overseas, you would have thought I was nuts. But that really is the potential we see unfolding over the next 10 to 15 years, was the development of the oils and the tight sands, the oil shales in the US, plus the tremendous growth in the oil sands in Western Canada. It’s very possible that we’ll see either imports completely bumped out as a source of crude oil supplier or at least be just at the margins. And by imports I mean, from overseas. Viewing this is North America, Canada and US together. But this is leading to a tremendous opportunity in the pipeline space.
All this supply is showing up in places where it hasn’t been for a long time or it’s grown well in excess of whatever it was at its prior peak and a good example of that is North Dakota. And so the infrastructure there has been quickly outstripped by the growth. And it’s leading to certainly great opportunities for our company. And we’re actively pursuing in investments to address this constraint. Well, transportation model acts just probably the highlight from all this. And this company is all about getting rid of transportation bottlenecks.
So, what’s our growth strategy? We clearly and it’s obvious from how we’re deploying our capital, very focused on growing our liquids pipeline systems. And it is, certainly the dominant asset in the Enbridge portfolio, whether you look corporately or at the partnership level. And certainly these assets are getting us great growth opportunities, we’ll talk to you on that more in just a minute.
In the Natural gas side, I mentioned in the previous slide, again it’s a good asset footprint that we have in Texas. And we see developing opportunities around that, around our basins. And we expect over time that we’re going to be able to grow that business. We also think long-run, it’s a good business to be in. Natural gas is going to play an increasingly important part of the energy picture in North America. And in South in particular as coal fire generation comes offline or population shifts to places like Texas to being on the front end of the gas value chain is going to be a great place to be.
Last thing, and we started touching on this more last year and Enbridge Inc also touched on Enbridge Day and that is, we really would like to position Enbridge Energy Partners as a drop down vehicle. So, a platform that the parent can use to drop more mature assets as they need access to capital at the parent level.
Clearly, Enbridge Inc, when you look at their growth profile over the next five years, that’s close to $35 billion of projects that they have secured. And certainly being able to use, whether it’s the income trust in Canada or Enbridge Energy Partners in the US is a place to drop assets down to is a great thing. And Enbridge understands as people as us all the time, why doesn’t Enbridge use EEP as a drop-down vehicle? They would like to but we’ve got lot of our own organic growth probably more than we can handle.
And so, drop-downs will come, it’s just something that will happen we think in the future. In the meantime, in Canada, there are drop-downs happening to the income trust there. So, Enbridge very much understands the value of the drop-down vehicle and how it should be used.
So, in terms of growth, we currently got underway two sections here on the liquid side and on natural gas. And the headline here of course is we secured $7.3 billion of incremental growth in 2012 and 2013, really driven around a couple of different strategies to enhance the access of refining centers in North America to Crude Oil supply being developed on the continent. So, historically we’ve always been working very hard over the – certainly last 10 years, very hard on bringing oil from Canada, down to the US Gulf Coast.
And the reason for that was – recognizing we’re having increasing supplies of heavy oil from the oil sands. The refining complex on the US Gulf Course has ideally started to run that – on that oil. And Steve will talk more about that strategy in a bit.
Also recently announced a development on the Eastern side of the Gulf of Mexico, a partnership with Energy Transfer, and Steve again will touch on that. We think that also is very good news and an example of enhancing access of wealth to new markets.
Finally, our Light Oil Market Access Initiative, and here it’s all about getting oil, light oil in particular to refining complexes that run that type of crude oil. Good example of that would be the refining complex in Montreal and Quebec City. They are light oil refineries tied to off-shore crude oil. They would love to have enhanced access to North American Crude, it will help their profitability. It will help certainly secure the resource supply to much more stable source in North America. So, light oil is all about getting growth in the Bakken, growth in Western Canada, and other areas to markets that naturally consume that oil.
Gas side, we’ve touched on value chain in prior years that’s still a focus for the company, and enhancing or drilling our existing footprint is important. Two key things we’ve been able to accomplish over the last couple of years is participation with our good friends in the enterprise in the Texas Express NGL Pipeline along with Anadarko and DCP Midstream, we’re very happy about that development. That will begin service in 2013. Also we recently – coming close to completion of construction of our AGX processing plant in the Anadarko Basin and John Loiacono will talk more about that.
Another area we’ve seen a lot of activity is condensate with all the development around the oil shales, there is lot of product that’s very light as lot of NGLs and trained in the oil. And stabilization of Con State is becoming a more important business for us, and again John will touch on that.
So, when all these projects come into service, what does it do to our business? It really takes what already is a pretty low risk business model and makes it even more low risk. And the key thing I would focus on, this is one of my friend Steve Neyland’s favorite charts is the ribbon chart, which shows how much cost to service or take or pay becomes of our business mix at the end of our planning horizon. So, much of that together with fee-based, we transitioned to an even more low risk business. And certainly from a credit rating perspective, from a unit holder perspective, the stability of cash flows that this model affords is a very distinct advantage for you.
So, all this leads to what we think our distribution growth target is going to be. We’ve talked about this 2% to 5% for several years, that’s still our expectation. And Steve Wuori who has always got something in the offer, along with John, who has always got something, he’s working on, we can do better than this as we enhance our access to capital.
I can’t have a presentation without touching on this. And we’ve talked about operational excellence and project execution already a little bit in the presentation. And operational excellence, we really focus probably as much as anything on integrity tool runs and how much we’re doing there and the technologies that we’re implying which are the state of the art, whether it’s crack detection or metal loss. The frequency with which we run, these types of tools is industry leading. We – looking at crack detection which is a very specific high technology version of hyper integrity tools. We ran about 40% of what was run in North America in 2012, so very active user of that technology.
But I want to talk about something a little bit different. And the example of trying to be an industry leader of the company in 2012, completed a training program for emergency responders along our pipeline system, basically utilizes your 3D video-gaming technology but it’s a way to help emergency response people along our system understand what it means to respond to a pipeline incident and provide training to them. And so, it’s a great way for the company to reach out to those that help us in the unlikely event anything ever needs to be dealt with. But again, that’s an industry leading move by this company.
Project execution, just to touch on that for a moment, we’re very blessed inside the Enbridge family, we’ve got about 1,000 people across the entire company so that the Enbridge Corporate and the Partnership that are engaged in our major project execution area.
Under our management today, and the major projects group is about 35 very large projects. Of that 35 projects, only two are either delayed or over-budget. Otherwise everything else is on time, on budget. And that is a tremendous accomplishment in the areas that we’re active and you think about the Bakken as an example, with the labor costs and all the issues up there to be able to stressfully get projects done on time, on budget is a great accomplishment.
So, in terms of key takeaways, yet it all starts with safety. And this company is going to be industry leader in that regard. We have some great projects under development in the liquids group and Steve is going to be up in just a moment to talk more about that. And he’s got a great presentation and he loves the business that we’re in and his passion will come across when he is speaking.
We’re still targeting that 2% to 5% distribution growth, no change in that. And Steve will talk more about that and coverage of distribution as part of his presentation. So, I think with that, obviously for the other folks in the room, debt investors, we are very focused on investment grade credit rating and maintaining that, active dialogue with our friends at the rating agencies. And we review our financing plans with them or the businesses going and that’s a very – again a priority for the company.
That’s a very fast overview of what you’re going to hear about today. And what I’d like to do at this point is just some general MLP related questions, we can take those. Otherwise we’re going to get Steve fired up, up here and get him going. Yes sir.
Ted Durbin – Goldman Sachs
Yeah, hi, it’s Ted Durbin, Goldman Sachs. Mark, just on the strategy itself, I mean, when you think about having the liquids business combined with the NGL business. I mean, is that a long term something that you want to keep together, would you have a – sort of, in the part when you think about – are there lot of operational synergies there, there is obviously some more commodity risk in the NGL business. Have you ever considered splitting the businesses apart and kind of keep the management focused on just the growth projects which really seems like it’s the Liquids?
Yeah, very good question, maybe standing up a little bit from the question. In the Enbridge family, we often, certainly we’ve done asset sales over the years. It’s not a thing that happens very frequently in the company. I use it as an example at the parent level, couple of international investments were sold in the past.
Inside the partnership we sold assets on occasion when we think it makes strategic sense. But right now, the way we look at the gas business is, it is an important platform of course for the future. Certainly, you always look – you have to look at what are your best financing alternatives, Ted. But certainly right now, we seek access being an important of our future. And so it’s strategically important to the company over the long run.
Ted Durbin – Goldman Sachs
And then, if I could ask one more, Mark, well, I got for you. If you think about the parent and they’re willingness to participate in some of your equity needs over time, I know that somewhat before that they owned 22% of the LP right now. Would they be willing to take on more equity as helping you finance some of these growth projects, you look at like a Williams or ONEOK, certainly the parent there has helped out. How are those conversations going on?
With the parent, we obviously incredible relations with the parent company. Enbridge has always been as you know, a very supportive general partner, whether it’s been investing alongside the partnership, it’s a more of a big expansion projects, as a way to lightening or minimize the financing burden. Or at different points in time, they have been there for credit facilities, directly invested in the partnership through additional units.
I think all those things are possible. There is nothing Ted on the – we’re going to do this tomorrow kind of thing that I can talk about here today. But I would just say, look at the past, Enbridge has always been there for the partnership that’s been needed. Now all that said, no one would like to go to dad and ask for money.
Brian Zarahn – Barclays Capital
Hi Mark, Brian Zarahn of Barclays. On the Natural Gas business, your EBITDA mix is obviously growing with your crude oil expansions. But can you talk about potentially shifting all of your processing contracts to fee based and what – is that possible? And secondly, on drop-downs, obviously it’s a much longer term. Can you give us a little bit color as of what some potential candidates are?
Sure, as to the drop-down question first. With respect to the logical drop-down candidates, the first place you’d look is any place we’re effectively joint venturing on an asset. So, Alberta Clipper, when we’re through with the market access projects, either Eastern access or the other expansions of the main line systems, those become immediate logical drop-down candidates. Then you go up a little further out in the map to more of the market pipelines its pure head, maybe the interest in Alliance, interest in Vector, Lanning in South, maybe Seaway. But really anything within the US becomes – as long as it fits the partnership definition it’s a possible drop-down candidate down the road. So that’s a big group of assets.
And with respect to your other question, as far as the – our NGL business is concerned, we do see this being an important part of our future going forward. And there are some business synergies that come from being involved from the customer relationships, we have a presence in Houston and Texas is helpful to the business as we develop the markets down there.
And as far as the fee based component in Gillian, going to that – it’s difficult but not impossible to transition from proper POL to fee based. There are certain times it probably makes sense to ask that question. When we come up for renewals we do look at that as an example, we went through a re-contracting with one customer we did shift with fee-based arrangement.
Sometimes we’re receptive to that sometimes we’re not, sometimes it’s just driven by the competitive landscape which we’re operating in, where the other folks maybe bidding for the gas. They’ll take that risk, the producer of use is kind of being alongside them if you will as opposed with – there are times we can do it, there are times we can’t. As the general rule, shifting to that is something we look to do. But looking at our gas business in the aggregate, fee based percentage of the margin is on the order of about 50% today and the balance is commodity.
Hi, there has been more talk obviously the last six to nine months about more drop-downs coming through down the line. In the past, drop-downs haven’t happened either A, because you’ve had so much stuff to do organically or B, Enbridge didn’t need the money. So, when you look at that long term goal of doing drop-downs. What’s the likelihood of one or the second being an impediment that’s happening? That’s number one. And number two, our drop-downs are not part of our sort of 5% growth, sort of in that three to four year timeframe?
Yeah, they’re not part of our 5% growth rate as it relates to the – what we’re projecting there, drop-down is not really factored into that projection at all. What’s the likelihood, it’s probably – it sounds very similar to what we talked about in 2008, 2009 where we thought okay, and Steve quoted on this the other day, he just was – where he said, we’re probably through with the main line, when clearly we’re not as far as expansion.
So, there is a lot of development still to happen in North America down steep over the years. The best one of all time, is the North Dakota system, that was dropped down to the partnership the 35 million, back years ago but that has been a fantastic drop-down. And we at Enbridge absolutely understand the value of the drop-down strategy and there will be a time when that makes sense. And we want to make sure that we’re in position to accept drop-downs when that time comes.
And the parent – the double-digit growth rate takes a lot of opportunities to, you need to execute on that. And so, again having EEP in a position to accept those from a parent is an important part of the company strategy. We’re running out of time so we’ll take one more and then we’re going to go to Steve.
Okay, good, thank you everybody.
Well, thanks very much Mark and good morning everyone. I am pleased to be here this morning to present the Liquids Pipeline story to you. And I was sitting there mulling Mark’s words and listening to him and mulling over whether I love the business as much as Mark says I do. And yet, what I find though I was wanting to disagree with him, it’s a fascinating business and we’re really gathered at a fascinating and unprecedented time.
When you think about it and we’ll talk about this, the more of the evolution of the North American picture is really stunning. We have US production at a high that hasn’t been seen for years at 7 million barrels a day or more in the last month. We have US imports at the lowest level in 12 years and that is remarkable when you think about it at 8 million barrels a day.
You have imported crudes at Tide Water being supplanted or replaced as Mark’s chart implied with crudes from inland from Canada and from the many solid shale plays all across the US. And all of that really generates opportunity for us in terms of infrastructure. So, I’d like to talk about the philosophy behind what it is that we do in part of loving the business comes with understanding the business and actually having a slavish devotion to the fundamentals of the business and looking at every change in the business and every trend that could really matter. So, we’ll talk about some of those things. But it really generates a lot of solid infrastructure opportunities.
I also want to talk a little bit about the rail phenomenon, that is very much in everyone’s hearts and lips and minds and there are those who love that too. And so, I’d like to – I’d like to put that in what I consider to be its proper perspective. And so we’ll come to all of that.
One of the most important things for us is, understanding what should be pipe markets and what shouldn’t be pipe markets? For example, we have believed very strongly and you’ll remember from prior years that there have been some aspirational indications in our presentations about the Western Gulf Coast to some degree especially at the Enbridge Inc sessions, the Eastern Gulf Course. And we have believed very much the goals are pipe markets and should be pipe markets.
On the other hand, Philadelphia is not a pipeline market for crude oil, it is certainly a refined products market for pipelines but it is not a pipeline market for crude oil, Washington State probably isn’t, California probably isn’t. And therefore we need to understand what’s the rail market and what’s the water market and what’s the pipeline market and we spend lot of time trying to understand what those things look like.
Generally speaking I would say this and hopefully this theme carries through. And that is that incremental heavy crude oil production which virtually all comes from the oil sand in Western Canada needs to go South, it needs to go to the Western and Eastern Gulf Coast. From an Enbridge Inc perspective, also for the benefit of the industry it needs to go West into the Pacific RIM market as well, that’s what the Enbridge Northern Gateway Pipeline project is all about for late in this decade.
But generally speaking between now and then, the incremental heavy, after filling Pad 2 and all of its refineries needs to go South. And generally speaking the light crude growth needs to migrate to the East. Even though our Trunk Line joint venture will carry light crude and frankly should replace the 400,000 barrels or so of light crude oil that’s arriving in the Eastern Gulf Coast market now by rail. Nonetheless there is a lot of light oil production into the Permian and the Eagle Ford and other places. And that means that generally speaking the markets have to go more to the east. And so those are the things that are driving us as we think about how to approach the overall development of the business.
In terms of key messages, Mark has touched on the most important one, we just can’t have any more incidents, we can’t have any more marshals. We simply are blitzing the system with everything necessary to make sure that we don’t have any more operational incidents, safety incidents as we go forward. And we are really taking a zero tolerance approach to that where no incident is acceptable.
The supply picture is robust. The differentials, the big differentials that rail is feeding on right now actually are mother’s milk to a pipe-liner. And that’s what we are looking to – we’re looking to address. Project implementation and I’ll come to that a little bit little later on is very much on track. And the multiple premium markets aspect of the system is extremely important. Because we have seen how quickly things change. How quickly rail has come up, how quickly differentials have moved around. How quickly production has come up in some unexpected areas. You never quite know in the future.
And therefore as a producer of crude oil, you want to know that you have maximum optionality to multiple markets. Do not be wedded to one market. And that’s really what the Enbridge system offers. Because when it leaves Western Canada or North Dakota that barrel can go to Minneapolis, Chicago, Detroit, Toledo, Eastern Canada, now Houston, Port Arthur, soon to be St. James, New Orleans, we can put it on rail and get it to Philadelphia that is the optionality that is absolutely critical because we just don’t know what the future holds. And we just don’t know what these differentials are going to look like and where they’re going to exist into the future. So, a lot of optionality is something we strive to achieve.
Just in terms of the basin connection and the positioning of EEP, it’s hard not to love EEP, don’t you agree. Because it is part of and it is connected to the largest and fastest growing oil pipeline system in the world, connected between growing and in robust supply and market demand areas that are almost inexhaustible. And so that is the positioning of EEP within that looking at the Western Canadian Oil Sands.
And also Light Oil plays and I’ll come to in a little bit. In Western Canada, the Bakken connected those two basins, access to the premium markets and so on that really is the basis for the competitive advantage that EEP has. And sometimes I feel in my frustration wondering why people don’t love EEP any better than a 7.8 yield would imply, is that do people realize the fundamentals here. And the fact that that it is very much an integral part of the system that is growing and actually has off-take contracts even though it is a common carrier itself. It has off-take contracts that will pull volumes through for the next 10 to 20 years with commitments that go all that long to Houston and Port Arthur and so on, Montreal being another example.
In terms of the supply growth, I won’t spend a lot of time on this. I think it’s pretty clear from a number of forecasts. But generally our view would be 4.5 million barrels per day of net new growth in North America, 1.5 a day coming from the oil sands, this is all to 2020. And then 3 million barrels a day coming from various light oil plays including the very familiar ones, the little purple one there though is the one that is a little bit of a sleeper and that is the Alberta Light Oil Plays in the Cardium and the Dunvegan.
And those are very much Bakken like in many ways. They are being drilled up along the Eastern foothills of the Rockies. And that’s something to watch in terms of light oil growth coming out of Western Canada that many people don’t spend too much time on. Certainly there will be more light oil growth and heavy oil growth by quite a margin in the coming years.
Mark had a chart, a slide very much like this. And basically what it shows is that foreign imports at Tide Water are being squeezed out systematically. So, between 2010 and forecast 2015, you can already see that the Canadian production and US production has risen. And then the – and by definition in a market which is basically stagnant with regard to demand in North America, that inevitably means that the foreign imports are being squeezed out. We expect that to continue very much out to 2020 which is as far as this forecast goes. But it really provides a lot of opportunity and infrastructure to get crude to the Brent and LLS markets to displace the foreign barrel.
We’ll hear a lot about energy security in the coming years I think. I hope we don’t hear too much about energy independence, that’s a much harder thing to identify. But certainly energy security that being the ability to know that crude oil is coming from stable friendly sources, home grown sources in many cases is very powerful. That’s what the SPR was set up to sort of counteract this idea that we are getting a lot of oil from years back from unstable sources around reliable sources. And so therefore this is a home grown way of looking at a strategic petroleum reserve.
In terms of the commodity price, this is just a quick snapshot. I think late last week and the numbers are updated a little bit from that but you can see that the Canadian heavy oil market WCS which is a blend of seven crude oils in Western Canada, called Western Canadian Select is priced at a very significant discount to its assay equivalent which is Mexican Mayan at the Gulf Coast. And at a pretty horrific discount to any Asian price equivalent for heavy oils so that is one very much critical need for the Canadian heavy oil producer, the oil sands producer is to unlock better pricing for WCS.
The other of course is Bakken, and there you see a $94 price, it was actually $90.46 yesterday or day before, close very much trading on top of WTI, both is a low ball $20 up from LLS or Brent. And so there is another opportunity for light oil to access the higher priced markets. So the differentials are shown down the right hand side of the page. And they are very striking.
And quite frankly they are the only thing that gives scope for rail, which costs anywhere from $10 to $20 a barrels depending from and to. And that’s what gives scope for rail, actually that’s what gives the attraction for rail. That’s what gives the excitement about rail as we sit here today are these very wide differentials. But it does point to the need to get to the Brent and LLS based markets which are at Tide Water.
So, in order to do that, a few projects I’d like to walk through. First of all the Western Gulf Coast access and I won’t go through all of the pieces and parts those have been announced, and this is Enbridge Inc’s work largely, that’s in the associated mainline expansion which is EEP. But basically that is the project to Loop or Twin or spearhead pipeline between Flannigan Illinois and Cushing and then to Loop or Twin the Seaway pipeline which is flowing south from Cushing into Houston with a leg over to Port Arthur. So, all of that is coming into service by mid 2014.
And basically it adds about 800,000 barrels a day of movement capability between Chicago and the Houston Port Arthur refining complex, that can be expanded with horsepower by another 200,000 barrels a day if we need to and we’ve got that in reserve and in our strategic planning as we look ahead. So, attacking of course the biggest refining market certainly on the western side of the planet, the Western Gulf Coast marketplace there which is over – I think this number is conservative actually closer to 5 million to 5.5 million barrels refining capability in the Western Gulf.
Then to the Eastern Gulf and this is the project that we just had a feeling it was coming when we did the EEP call on Valentine’s Day. And darn it, we couldn’t talk about it until the next morning on the Enbridge Inc call. But this has been a very important development that we’ve been pursuing with Energy Transfer. Energy Transfer of course announced last summer that they intended to take one of the three Trunk Line gas pipelines in that south to north quarter and convert it to crude oil, our 30-inch line.
They applied last July for abandonment in gas service and placing it into crude oil service. And they expect an answer from the FERC probably by the early second quarter, mid-second quarter, although certainly I’ll let them and the FERC speak for that. But that is part of the lynchpin of this project is really the conversion of the Trunk Line system which goes right through Memphis, which is important because there is a 200,000 barrel a day refinery at Memphis, Valero has it.
It’s fed from the south and it’s been publicized recently that one of the things that they are doing rather than taking the LLS based price crude into Memphis. What they’re actually doing is barging crude down the Mississippi River to St. James putting it in the Cap Line and transporting it back north or railing it into St. James and then putting it into Cap Line and moving it back north. The Cap Line moving of course, the 40-inch line from St. James up to Patoka flowing very little these days and yet it does flow in supply Memphis.
So, a very important project because it fits in with our Southern Access extension which we announced before the end of the year between Flannigan and Patoka with Marathon as the anchor customer, gets us into the Patoka hub with bigger capacity than our Mustang and Ozark systems can deliver into that hub. So we can serve eastern Pad 2 refineries with light oil from the Bakken but also supply the Trunk Line conversion project here that will go into St. James.
We announced a capacity of about 400,000 to 660,000 barrels per day depending on the level of market interest and depending on the heavy light crude mix that comes from this project. But it certainly is a major project that actually I think should be able to supplant the large rail movements into St. James that are taking place today, which have been absolutely astounding and have grown to nearly 400,000 barrels per day of largely Bakken crudes that are arriving in St. James today.
This should be a pipeline market, this should not be a rail market. This absolutely is a pipeline market. It will also be supplied to some degree by Shell’s ho-ho reversal and that is in the Christmas time, Euphemism or anything like that. It actually means home at a Houston which is the direction that that line has flowed for a long-long time. They are not going to flow at east bound from Houston back to Hama to into that New Orleans Eastern Pad 3 marketplace.
It is limited in capacity. I believe its 22-inch line and so its capacity will be limited. But it will provide another outlet for some Eagle Ford barrels that are piling into Houston to get eastern into this market. So, again, I think this really needs to be a pipeline market and that’s what this project is designed to put into place. And we can certainly talk about it more if you wish in the Q&A.
In terms of projects that we’ve announced before, I’ll go through them quite quickly because we have announced them in some detail and I’m coming to a slide that I just still can’t believe Sanjay Lad was clever enough to build, that’s a few slides down. But I will recommend it to you when we come to it. But the Eastern access project which we announced last – I think it was last fall, consists of a number of EEP and Enbridge Inc initiatives, the line five expansion, which should go into service next month, the 50,000 barrels a day of additional light oil capacity shown there in yellow over the top of Michigan and Wisconsin down to Sarnia Ontario, that’s very much a part of our initial line nine reversal for the first piece from called 9A I guess it is on this or we call it 4A for reasons that I probably never understand in a hurry.
But the Sarnia, the west over piece of line 9 to serve the Imperial Exxon Nanticoke Refinery in Ontario is what is behind the line 5 expansion. That should pull more volumes immediately on to the – on to the North Dakota system, because it will be largely, it will be all light oil and largely light oil from the Bakken that should move on that expansion there.
Also the spearhead north expansion also known as line 62, a very important piece because we have too much capacity in the Flannigan compared to the amount of capacity that leaves Flannigan and so therefore we’re expanding and actually doubling that short line between Flannigan and Chicago. Replacement of line 6B which is moving along well now that we have the Michigan Public Service Commission approval to do that project, that’s moving along as we speak, Line 9 reversal which we have talked about.
And then also the twinning of the Toledo pipeline partially to get more crude into both the Marathon, Detroit refinery as well as the refineries at Toledo which would be VP and PBF.
So, that was the eastern access program. Then we announced the LOMA, the Light Oil Market Access Program which again is a combination of EEP and EI projects that beef up the capacity of the mainline, expand Alberta Clipper, expand the Southern Access pipeline that we put in just a few years ago, expanding the Eastern Access line 6B adding more horsepower to the new line 6B to bring it to over 500,000 barrels a day of capacity.
And then reversing line 9 of course all the way to Montreal and bringing that to 300,000 barrels per day as part of this Light Oil Market Access Program. Also the important piece was the Southern Access Extension which you would remember we tried five years ago to get approval and commercial support to do that. We were not able to do that and now we have been able to achieve that in that right away that we had secured five years ago. It’s only a 169 miles from Flannigan to Patoka and that line has long needed to be built in that corridor and now it will be.
We then have the Bakken Expansion Program and we did receive final regulatory approval so we have the BEP or the Bakken Expansion Program now declared in service as of March 1, so that was an important piece. And that’s to deliver a 145,000 barrels a day of capacity from both North Dakota up into the mainline system at Cromer Manitoba.
We have also the Bakken Access Program and the Vertical Rail Program and then the Eddie Stone rail offload facility in Philadelphia as somewhat of a match to the Bur-Cold Rail Program. And I believe Bridger Transportation and Trading has made an announcement regarding their use of those facilities. So that’s the North Dakota picture.
And then of course we have project Sand Piper, which we’ve applied to the FERC for a petition for deviatory order around the tolling that would be a common carrier system. I think it became clear to us as we prosecuted the Sand Piper concept that contract pipelines were not going to achieve a lot of success. ONEOK proved that with the line that they had that was going to go to Cushing. Producers a quite reluctant to sign long-term pipeline commitments in the Bakken itself and why, it’s because they believe they now have a viable option in rail. And therefore that’s the fly wheel that would say, they would love to move on pipe, it’s cheaper if it goes to the right markets. But they also have rail as a viable option. And so therefore getting pipe commitments proved to be very tough.
And we decided to do Sand Piper as a common carrier, roll into the North Dakota system with a surcharge and that’s what we’ve applied to FERC to do. We have a number of letters of shipper’s support from those that are growing in volume and want to access more capacity to better markets on pipe out of the Bakken. And there is a few letters of objection from those who are not growing and their intention to move volumes out of North Dakota. And who simply want to keep the toll exactly where it is today. And that’s basically the layout of the Sand Piper debate as it stands today.
So, now we come to the Sanjay slide, which is – which is – and I think I recommended because our call was (inaudible) to bring it home. And she was impressed with it then. Imagine tonight when you come home with this one that now has also the Trunk Line JV that we couldn’t put on the old map, now on it. And it shows you the complete picture and I hope you will use it as a handy reference for almost everything that Enbridge Inc and EEP are doing in relation to US related movements of crude and pipeline projects. It really pulls it all together, EEP on the left hand side box, Inc largely on the right hand side box and really pulling all of these projects together with their CapEx and generally with their capacities.
And the thing to remember is that – all of this is designed not only to reach those markets and provide optionality but also to pull volumes through the Enbridge Inc and EEP mainline system. That really is – we are a volume business and that really is the foundation of what we’re doing here is ensuring that the best markets are open so that volumes will pull through the mainline. By contractual commitment on the downstream end, those volumes are assured to flow.
The other thing that’s been absolutely critical and it tells you the North Dakota story, and quite honestly, the Saskatchewan story on the Canadian side of the border which has also been suffering from loss of volumes due to rail. The fact is the pipeline don’t go where they need to right now. The pipelines don’t get to St. James, that’s where the crude needs to go, they don’t get to Philadelphia, they don’t get to St. John, New Brunswick, and therefore you have seen rail basically take those markets. And so it isn’t hard to understand why that is.
And so these projects ensure that the crude which should move on pipes which is most of it will move on pipes. And that’s the longer picture here as we look at putting all of this together.
This slide is just a reflection on the entire look at getting to the Brent and LLS based markets. And in total, there is 1.7 million barrels a day of new market assess that we are providing that will alleviate price dislocations. And incidentally to a rail operator that would be words that are not sweet to the ears, and that is to alleviate price dislocations. Because rail as I will come to in a minute lives only on large price dislocations and everything that we’re doing here along with others frankly and rail itself becoming a self-fulfilling prophecy and moving high volumes to Tide Water markets. Inevitably the market is efficient and it will close those price dislocations. And that’s when pipe survives at a fraction of the differential that rail can survive at.
So then taking a look at rail, I just want to spend a minute on it, because we are involved at Bur-Cold and North Dakota with our loading facility, now loading 80,000 barrels a day. There of North Dakota Bakken crude. And then the Eddie Stone Rail Project that we have under construction in Philadelphia which is right in the heart of the Pad 1 Delaware River area refining complex, just south of the Philadelphia airport. If you lift-off on runway 1-6, you will fly over Eddie Stone in about a minute, no less, because it’s just literally a mile south or so of the North-South runway at Philadelphia.
So, we are involved in the rail business. And as I said at the beginning there are markets that are probably longer term rail markets or rail and water markets. And those would be the East Coast Philadelphia for example, would be a prime one and the West Coast, Washington State. I think there will long be a play for rail movements from North Dakota to Washington State refineries as we’re seeing today and also to the California refineries.
Rail is actually serving a vital need. Rail has been in many ways the savior of the shale play producer in the last year or so, in being able to get those volumes out and move them to the markets where they need to go. Just before I come to concerns about the rail business, let me give you two other tit-bits that are very important.
The rail network is extensive. I should have thought of it Sanjay to bring a map of the rail network in the United States. It looks like a map of your veins and arteries and little capillaries and it’s unbelievable. The rail network in the United States is astounding. It just covers black, the whole map. So, the rail network itself is very impressive. Rail offers agility and speed to market, changing destinations. And relatively fast transit times as compared to pipelines.
So, to give rail its due, it certainly is serving a need that is for today. However there is a number of concerns that I think we are hearing about, we need to hear about and we need to be thinking about.
The first is what I mentioned and that is, you’ve got to have high sustained differentials. And if you don’t have differentials of $15 to $20 a barrel, you are not in the rail business moving to that market. So that would be point one, you need $10 to $20 a barrel differentials as opposed to $5 to $8 a barrel differentials to survive on pipe.
In order to move 80,000 barrels a day ratable you need 2,000 railcars at your disposal to move 80,000 barrels per day. And so that’s a fact worth remembering. 80% of the cost is loaded mile charges, fuel surcharges, switching charges and the like. And so, about 80% is that high variable cost. And then the lower committed cost would be the cost that you have committed to loading or unloading or loading and unloading facility and to the railcar itself.
And just in round rule of thumb numbers, you’ve got about $3 to $4 a barrel in that crude before it ever moves because you’ve committed to the car and the loading facility and the unloading facility. Those fees depending on exactly where they are add up to $3 to $4. So that’s something that a producer also has to consider especially when pipe options become available at $5 to $8 a barrel recognizing, they’ve got a $3 to $4 a barrel sitting and they haven’t left North Dakota yet, or they haven’t left Western Canada yet and so on.
And then the other thing and this is just a quick sense of things we will hear about I think in 2013 because we haven’t heard about them. We haven’t heard anything up until now about railcar life, we’ve not heard much about railcar life. But the fact is that – most railcars move between 10 and 15 times a year, about that many trips in a year and they last five to seven years.
In a unit train configuration, high volume, ratable delivery, that means consistently moving the volumes to the market, you’re moving that car 50-52, maybe once a week, so 52 times in a year. The life drops to 2-3 years. And the reason for that is think about the amount of things that roll around on the truck which is the undercarriage of the car, if the tank which carries the oil but then you have the undercarriage which has numeral number of bearings and wheels and axils and everything else.
And so, we will start to hear more now as we get into the truly high volumes coming out of North Dakota, as one example. We’re going to hear more about railcar life, railcar rehabilitation, railcar servicing and a phenomenon called bad orders. And bad orders are when a railcar is declared not fit to dispatch, you shunt it to the side and secure another one. Bad order rates I think hover in the 3% to 6% range right now. As cars get pushed harder and harder and harder, maybe that rises. And I know that the rail companies are doing a wonderful job of recognizing that and reacting to it.
But also to say, it’s not as easy as it sounds. And we are discovering that because we are as I said in the rail business ourselves especially between North Dakota and Philadelphia.
Moving then quickly to something that Mark touched on the major projects area and I won’t spend a lot of time here other than to say that we formed the major projects group five years ago, little over five years ago now under El Monaco as the head of major projects. And he would have appeared at this session to talk about that. that Became our in-house construction company, that became I think the total is close to 2,000 people enterprise wide, people who are dedicated to just building all of these projects and putting them – getting them ready for service.
They are not concerned with business development, they are not concerned with operating issues other than the facilities that they’re designing and building being ready for proper operation and so on. And that has really paid dividends, a lot of tremendous success in being on-time and on budget with these projects. And I think that that’s why even though we wondered how long we would need a major project’s function, we have decided that we needed, it’s an integral part of what it is that we do.
This slide is just a quick snapshot of the EEP projects that are major projects that are under management right now. The only one that’s delayed or has been delayed is the first of the line 6B 75-mile replacement program and that was the MPSC approval process that took longer than we anticipated it to take.
We’ll focus on operations. And here the objective really is to be the industry leader in safety and integrity dimensions. Mark mentioned that we ran last year about 40% of all the high technology smart-pig runs. And honestly we have been blitzing the system to ensure that we understand all of the pipe we have – all of its characteristics and we have been very aggressive at examining that pipe.
There was a period of time where we ran more hi-tech crack detection tools than the rest of the world combined. And that I think is testimony to our devotion which has always been there actually to continually push the frontier of detectability of pipeline defects.
So there are two frontiers right now that are active in the pipeline industry. One is the ability to detect smaller and smaller crack features in pipelines and the other is the ability to detect smaller and smaller leaks releases from pipelines. And those are two key frontiers that we are very much focused on.
On the integrity side, we’re actually using medical imaging technology based tools that essentially end up giving you an MRI or Cat Scan or both of the pipeline as the tool passes through taking measurements every three millimeters along the inside surface of the pipe projecting through the wall of the pipe and reading what that wall thickness of the pipe looks like, very much like a diagnostic medical test that you might have done.
It is the largest program in the World and it’s accompanied by a number of other things, including surveys, river crossing surveys that was a concern across the industry in the mid-west after the 2011 floods. And a lot of work was done on river crossings all around the mid-west especially because of the scour caused by the flooding. So a lot of work being done on that, lot of work being done on our rotating equipment, seals and pumps and other things that can have releases within pump stations.
Also, with regard to leak detection itself, we’ve always had a system called CPM or computational pipeline modeling or monitoring. But what this is really doing is cutting down on the amount of mass between measurement points. That’s an important variable and how detectable a leak really is. And one of the things that the public is often curious about is why would a pipeline company not just simply know that they have a leak.
And the reason is that Liquids Pipeline Systems especially high volume ones have a lot of fluid of different densities moving through and it is not easy just to simply read that. So, we are making it easy by virtue of focusing on adding flow measurements and pressure measurements at much more frequent intervals just as an overall sense. And also understanding what the alarm is coming from these computational models really mean. So, that’s an area that we’re working on hard.
As well as through the industry also, through the ALPL, the Association of Light Pipelines and the API, there are a number of work teams that have many companies involved that are attacking these various things as well from the overall industry dimension.
So then, finally the key takeaways again are around operational excellence, the robustness of the dynamics of the business overall, the infrastructure opportunities that we have and that we are pursuing and that we see out ahead of us and always maintaining a lot of optionality and offering a lot of optionality for the crude oil shipper across the system so that now and into the future they will be able to access the markets that mean the most. And that means really spending everyday on understanding where those markets are today and where are they likely to be tomorrow.
So, with that I’ll open it up for questions.
Just a couple of quick questions. We’ve known that you have a dog in the hunt so it might be a little bias to answer to start with. Basically these are two big projects that have right now in front of the Federal Government, the Reversal Project as well as XL and it seems that both would be needed unless you think they are. So I guess the question is, do you think both would be needed? And second if not, how do you handicap that to dog race or to horse race?
Let me just clarify, when you say the reversal, what are you – are you talking about the Trunk Line?
The Trunk Line reversal yes, sir.
Yeah, that’s actually a little bit different from Keystone XL, it goes to a different market, it does not cross the border. It actually only requires FERC action as opposed to any presidential permit action. So that is quite different from the XL approval.
We have said publicly and continue to do so that Keystone XL should get it’s presidential permit. The arguments raised against it are not valid and therefore it ought to get the presidential permit we’ve said that before. And it’s now much influx in view of the actions that have been recently taken around the draft environmental impact statement and the final decision by the Obama Administration.
So, I can’t handicap that other than to say that all of our planning has assumed that Keystone XL will get its approval and that it will move the volumes that it’s contracted to move. So, we have incorporated that into all of our thinking.
Okay. I guess a follow-up then would be – taken that do you think both projects will bring various types and forms of crude oil down into the Gulf Coast region. And as you earlier said, will probably push out rail to the Gulf. Did you comment on what kind of excess capacity – rail capacity you might end up in the Bakken once those two pipelines do start moving the crude down and the rails no longer go into the Gulf Coast and what kind of impact that has on your current investment and your future rail investments you might want to make?
Yeah, I think that’s a great question. I think from what Trans-Canada has said, they intend to move about 100,000 to 150,000 barrels per day on the XL pipeline from the Bakken. So, if you assume that starting sometime in 2015 and then you look at our Sand Piper project which has a similar time schedule which would add about 225,000 barrels per day of capacity out of the Bakken, those combined are something on the order of 400,000 barrels per day of new pipe capacity coming out of the Bakken.
There is about just under 0.5 million barrels a day of rail movements out of the Bakken today. About our North Dakota system is flowing far under its nameplate capacity as well. So there is probably 75,000 barrels a day of space available, reliably on our system to come off rail plus the Sand Piper, plus the XL. So, if you just kind of look at it in terms of mathematics that leaves maybe something like 100,000 barrels a day which – some of which will move to Washington State. I think those movements are pretty reliable. They really can’t get to the Washington State refineries any other way, some movements to California.
Not a lot of rail movements into the Gulf Coast right now. And therefore, our Flannigan South and Seaway project nor the XL project will really displace a lot of rail in that market. It really is the Eastern Gulf market, the St. James market where I see a lot of rail displacement taking place.
Steve, looking back at that Sanjay’s slide, well it’s called Sanjay’s slide. I just wanted to offer a small opportunity for improvement. The one thing I saw missing was perhaps what could get added is targeted returns at what volumes. And I was wondering if you might be willing to talk a little bit about at 90% volumes or this amount of volumes what sort of returns you get, particularly from you having pointed out the high-cost equity capital that you have and the GP tag as well, so the higher cost to capital that you have versus some other companies. Just give you the opportunity to talk to target returns on these pipes, in these projects?
Yeah. Actually Steve Neyland is saying that he – in his deck actually wants to cover that in some detail because it is I think really critical to the EEP story. And that is the returns but also the lower risk of EEP say relative to Enbridge Inc in regards to volumes. So, why don’t – if you wouldn’t mind David, can we nail it then and see where we go with it at that point.
TJ Schultz – RBC
TJ Schultz with RBC. I guess first on some of the comments you made on railcar life and some of those conversations starting. Maybe if you could comment on – if you see this maybe being some type of railcar bottleneck that would help push or kind of shift producer interest into some of the pipeline projects that you laid out are excess capacity or if at least those conversations are starting to be had with the producers?
The issue of railcar life though in the minds of the rail company is certainly it being their business really has not surfaced to any degree. So it’s very, very early. I think mostly what it does is not say that railcar life would be curtailed but costs will go up in order to ensure that railcar life is extended. Maybe that’s the key operative here is that railcar costs generally will rise due to scarcity which they already have but also this other factor.
And I think that then plays into the size of the differential necessary to make rail movements attractive. So if you have generally cost pressures tending to rise and differentials over time tending to fall. I think that’s the dynamic that will really play up in the rail debate.
And in the meantime also, pipes being built to those same markets, which will be much more cost effective in the course of time, so that whole railcar life phenomena really I think is an economic issue ultimately because railcar trucks can be maintained and will be maintained. And it’s just a matter of whether the costs I think will be rising given the high demands being placed on those cars like never before. You’ve had our tanker car that as I said they have moved 10 times or 15 times in a year prior to today’s environment, now it’s moving every week and it’s moving 1,500 miles one-way every week. So that changes the dynamic of the railcar tanker truck situation. And I don’t – I’m not deep in that myself, certainly I’ve not lived in the rail world. And so the rails will certainly speak to that as they see fit.
TJ Schultz – RBC
Okay. All right, just one more shifting gears back to the JV, the Trunk Line JV. If you could comment maybe on the open season or what level of producer commitments do you need to move forward or when would you expect some realization there and then maybe talk about the mix of light versus heavy that you would envision there as you compete with some of the light volumes coming over from the Eagle Ford maybe how that ties into the refining capabilities there what you would put on the water?
Yeah, yeah, I think it’s a very good question. We will see what the open season and the discussions that preceded generate, I don’t want to foreshadow what that could be. However, it is true that there is a lot of intense interest in both light and heavy movements to those refineries. Clearly the light movements are attractive, just given how much is arriving in the Eastern Gulf by rail today, nearly 400,000 barrels per day.
And so arguably and depending on where it’s coming from all of that should be accessible or at least in large part accessible to the pipe project. But there is also demand for heavy crude and that’s part of the dynamic we’re going to be watching closely as the capacity of the pipe as you – as a function of the mix of heavy and light crude oil. There is an inexhaustible heavy market, quite like there is in the Houston Port Arthur market but there is a substantial heavy crude market.
And so, we aren’t ready yet to pin what we think the percentage of heavy and light will be. I think probably it will be greater than 50% light though would be my guess, just given the demand for the Bakken. And Bakken like crudes into the Gulf Coast, Eastern Gulf market but I don’t know that we’re ready enough now to say exactly what that’s going to be. We’ll see how the discussions go. We’ll see who steps up to commit frankly.
Maybe down there, Ted and then Winfried in the front a little bit.
Ted Durbin – Goldman Sachs
Can you talk a little bit about upstream maybe even on the Canadian side of the mainline. How much excess capacity do you have now to bring heavy out of the Oil Sands itself, how much can you expand that yet they just pump stations versus having to build a new line? And then where do you fall in terms of the presidential permit and needing to get a presidential permit to maybe move additional alliance to get across the US side?
Sure. Well, the application active right now with the State Department is to amend the Alberta Clipper presidential permit from 450,000 barrels per day up to 800,000 or 850,000 barrels per day which is close to the ultimate capacity of that pipe. Frankly in all light oil, it would move more than that. But that’s the active amendment application right now. The State department is moving on that application they released last week that they’ve chosen the third party to review the environmental impact statement which is really what is required as this amendment goes forward. So that I think is moving forward quite well. And that really is the big incremental capacity that’s available to us that we’re working on right now, the 450,000 to 800,000 or 450,000 to 850,000 range as you cross the border.
Steve, if you could comment or I don’t know how much of this you’ll be able to answer. But this is on the Trunk Line JV. If we go back in history a little bit, with the Seaway pipeline, originally there was a proposal called the Wrangler pipeline between enterprise and Enbridge. And then eventually we ended up with the Seaway reversal that this now Enbridge Enterprise, I’m sorry the Wrangler was Energy Transfer Enterprise – I mean, Enbridge sorry.
Lot of Es.
All the Es there. So, I guess the question I have is you’ve got a competing pipeline in there Cap Line. And there has been talk for a long time about the possibility of reversing Cap Line. But the push back on that is that – they keep it moving crude, possible to move crude north for optionality from the West suppliers. And so what’s the probability I guess of the owners of Cap Line deciding well now that there is this competing pipeline out there we’re going to move forward on reversal and that would indicate the Trunk Line opportunities. So if you could – I don’t know to what extent you can comment on that and keep all the competitors involved but any thoughts you share would be helpful?
Yeah, well, it is a little hard to comment out of line that we don’t know. And so I’ll be very careful about doing that. I mean, clearly plains I think a couple of weeks low on their call was talking about the potential for the reversal of Cap Line. They have the largest share of the Cap Line but Marathon and BP still are in the ownership mix.
And so, we have of course done our own assessment of the likelihood of that happening because it has been talked about for a long-long time. The other thing, I believe plains said was that it could also move condensates north from the Gulf Coast in its current direction to feed say our Southern Lights pipeline which moves condensates from Chicago to Alberta or the Kinder Morgan Coaching pipeline conversion which is designed to move 75,000 barrels a day of condensates basically in the same geography, Chicago up into Alberta. So, Cap Line could well be involved, frankly is involved in doing that. But that requires a north bound direction.
Reversal of Cap Line I think requires a unanimous owner decision on the direction since it’s an undivided joint interest line. Each company has its share of the capacity and certainly they have a say on which direction the flow goes. And so that is what it does require. Probably there is a debate about whether you must have a north bound conduit, some would argue absolutely. You must have a north bound conduit of some kind between the strategic petroleum reserves at St. James at the head-end of the Cap Line and upper pad too. And so, there is a lot of factors that go into that question. And I think we’ll just let all of that evolve. I’m sure those three owners are debating that periodically.
All right, that’s helpful. And then the other question is just, if you could clarify for us supposing XL doesn’t go forward when would Enbridge’s pipelines, you’re on the mainline system – when would that be full, because we keep hearing it’s about two years or so for being full itself. Could you comment on that?
Yeah. Well, I think in relation to the Trunk Line joint venture, when you look at the way that Trunk Line could be fed. We think about 250,000 barrels a day could come through our system with current expansion plans, Ted’s earlier question of the Alberta Clipper upsizing and so on. You also can feed it with Keystone and with now Spectra and their ownership of the flat pipeline that comes into Patoka. And our Ozark System moves up into the Wood River of Patoka area as well. So, a number of different ways that Trunk Line itself could be fed.
We are of course looking at our mainline system after Alberta Clipper is fully expanded. And I think we have some options there that are attractive. We’re not ready to announce them or discuss them at this point. But we certainly have that in our minds all the time in relation to what else can be done with the mainline to feed more capacity to the ex-Chicago region. So I mentioned that the Flannigan South and Seaway System after its construction will still have another 200,000 barrels per day of expansion capability in that alone. And then we’ll see what the Trunk Line numbers end up looking like. So, lot’s of potential there but nothing on the mainline at this point. Winfried.
Winfried Freuhauf – W Fruehauf Consulting Limited
Winfried Freuhauf from W Fruehauf Consulting Limited. Steve, I have a question on your slide 6, but before getting there I just have a little introduction. Globally I look at the demand and supply for crude petroleum as a system of communicating tubes. And if the demand is pretty well fixed perhaps though we can see alternative for excess supplies, but if we have exhausted demand and storage, then what I think is going to happen is that prices will have to come down not only the Gulf Coast but everywhere around the globe.
So, getting now to slide 6, as I understand it that the differentials shown on that slide underpins the rush to the Gulf Coast. But that assumes that Mexico and Venezuela will just roll over and go under without a bother and is that realistic?
That’s a good question. With the passing of President Chavez yesterday, it’s an open question as to what’s going to happen in Venezuela. I don’t think what is too much to debate though is the fact that regardless of whether there is a change in policy there will be some time required before foreign investment returns to Venezuela and the oil industry and production rises. So I think that’s one to watch.
I quite honestly am not sure that there is a policy change in the offering. President Chavez was usually popular among many, not so much among the elite who now live in Miami, but certainly among many. And so, I’m not sure that we will see a rapid policy change that being to attract foreign investment back into Venezuela to stimulate the ONEOK belt production and other geologic areas.
Mexico of course the decline in Maya continues. There doesn’t seem to be anything in particular, that’s a geologic as well as a political problem. And therefore there is nothing that seems to be turning that around in a hurry. And therefore the Canadian heavy crude barrel which is current, it is real, it is growing, really has the opportunity as we’ve been saying for a number of years to displace those heavy crude equivalents in the Gulf Coast market. And I really think that’s going to continue.
I think your broader question though is a fascinating one. Because sometimes people, practitioners act as though Brent is inviolable price that Brent is what it is and it’s just a matter of figuring out what kind of a discount to Brent everything is going to trade at. But I think your point is a good one. In my view it’s inevitable that Brent must fall. As more and more foreign sourced cargos are diverted effectively away from the United States, they will be penetrating other markets.
The Asian demand is not appeared to be quite as robust as we had all been thinking at least not in the near term although it’s strong. And so I think that’s fascinating. What does that mean for the North American players? It means that we must watch the differentials carefully, it means that they are likely to shrink. And that is why pipelines must go to markets like St. James because that can’t be a market that relies on $20 to $30 differentials from inland pricing. It has to be a market that is much tighter than that which is what pipelines are able to deliver into.
So, that’s I think the question. If Brent thinks the differentials shrink along with that. And I for one don’t believe that Brent is an inviolable unchangeable price, I think inevitably with diversion of crude away from the largest market in the world, except China was the largest importer for one month, weren’t they?
Winfried Freuhauf – W Fruehauf Consulting Limited
But other than that it’s the United States and with the diversion of cargos away from the United States, you will clearly I think see a softening in Brent pricing over time.
Winfried Freuhauf – W Fruehauf Consulting Limited
Supplementary question, if one listens to the Pitchman producer’s things to sense a bit of a pull back on future power checks. Will that in any form or shapes affect Enbridge’s plans for the non-secured project?
Yeah, Winfried, we spend a lot of time on our own internal forecasting with that question exactly. Basically handicapping lease by lease and project by project, whether we believe that they’re going to go ahead, what the probabilities and so on? And that generates our growth forecast. Cap I know does the exact same thing being probably a little bit more constrained by the fact that it must be careful with its 130 members not to overtly say that one is going and one is not going.
But we spend a lot of time on that and partially it’s a function of what we see on slide 6 in large part and that is that you’re selling a relatively high cost heavy crude at a pretty vicious discount to the world price either in Asia or on the Gulf Coast. And that really is the bridge that needs to be repaired if you will. And then that’s what we’re trying to do with these projects.
I also think that there is some chicken and egg involved, with greater certainty of market access and pricing then the companies that are on the fence as to whether to move forward with their Sag D project or mining project will be more incented to do that that with less certainty as to whether a West Coast access is possible or robust Gulf Coast access and what the pricing environment is. It isn’t surprising that there is some caution that has set in, in the oil sands environment.
Steve, you commented on rail in the US, but can you comment on where you see developments on rail from Western Canada?
Yeah, there has been some announcements about Pitchman moving from Alberta to primarily the Houston Port Arthur market. Generally it has been smaller producers who have secured heated railcars that are called the heated coiled railcar that has to stay hot basically because the economics demand that the Pitchman be moved without the constant in it. So it’s a very viscous product that moves as long as it stays hot. If it doesn’t then there is, hockey-pocks for sale.
And so that is happening and of course CN Rail, CP Rail are quite enthused about the movements from Alberta to those markets. And in many ways because of the compelling differentials that makes a lot of sense. I think over time with the pipe access being unclogged in various ways that probably goes away. That’s a $20, $21 movement a barrel to do it that way as opposed to $10 to $17 out of the Bakken let’s say. And so therefore it is quite an investment to move by rail from Western Canada.
The Saskatchewan Bakken is moving, there is a lot of crude moving by rail of like – Bakken like crudes coming out of Saskatchewan. I think that’s going to continue for a little while, getting again to the Tide Water markets that pipes can’t access right now. Other questions, there is not even a right light on here, which is nice.
Just a follow-up since your red light is not on yet. My earlier question, it seems to me if I do the math based on what you said earlier, that there is going to be excess capacity up there in the Bakken for loading facilities if not loading facilities on rail course. If we’re going to place 400,000 barrels a day and 2,000 cars per 80,000 barrels, let’s call it 10,000 cars.
Two to three year of life, okay, so let’s say they are absolute – become obsolete and say they want to replace them. But the on-loading facilities up in the Bakken, that are being used to load that crude, if we’re already going East and West with other people to meet those needs, it seems that we have an – we right now might be in an over-developed area. And any new development in the region for rail would not make sense. Does that seem correct to you?
That makes sense to me. We have basically 800,000 barrels a day technically of loading capability in the Bakken right now, just to load rail cars on various facilities, everything from big unit train facilities to smaller manifest cargo type of facilities that can’t load 118 car trains. That makes sense to me. And yet we still see new facilities being talked about and proposed. And I suppose that gets to the issue of geography. And exactly where the loading facilities are relative to where individual producer’s lease-holdings are. And maybe that’s part of the play that one can miss on a quick flyover.
But on the base numbers, I couldn’t agree with you more, with 800,000 barrels a day of loading capability in the Bakken, basically in place today it is hard to envision the need for more growth in loading facilities there. Anything else? Okay thank you very much.
Great, thank you Steve. Actually we just received words Steve, that your Twitter account is experiencing elevated traffic, so maybe keep an eye out there. We will break now for 15 minutes. And we’ll look to reconvene at 10:45. Thank you.
Good morning. My name is John Loiacono, I lead the partnerships and for gas gathering and processing business. And so, I feel sorry for me but following Steve Wuori is of course probably the tallest challenge of our career in the presentation after listening to him.
We’re going to go into our key messages. And first you move forward to the slide two there, these are key messages like you need to take away from this presentation. First and foremost, our highest priority is our focus on operational excellence, just an integrity and our operating our systems safely. We believe this will be the foundation in which we grow our business and provide reliable service to our customers.
We also have a solid business in the portfolio, they are strategically positioned and active natural gas basin, and we also have a number of growth projects that we plan to execute on in various region and we’ll cover in more detail in a moment.
So, first we’re going to start off with some of the fundamentals of the gas business as Steve did. We expect supply growth to continue as it has over the next number of years. Both of this has been driven by the Shale and unconventional gas plays are ongoing. And you can kind of see there has been a little bit of a flattening of supply and this is all attributable to more of the active gas has gone on drilling in the more of the rich plays of the wells, so we have quite the productive that we’ve seen in the more or so in the dry shales that was occurring couple of years ago.
So the other thing we’re seeing of course is well producers are drilling as wells faster and seeing a lot higher productivity. But we’re looking roughly by the end of 2025, EIA is projecting to be about 75 bcf a day and us as well as some of the other people that are forecasting the supply they expect that number to be more in the 85 bcf a day range.
Now the chart on the right side is the demand forecast as presented by the EIA, and it’s projected to go to roughly 75 bcf a day and some estimates as well to be higher. And a lot of that gap would be covered by the potential exports of LNG.
Now, we believe the natural gas demand will be driven primarily by electric generation growth as well as the continued retirements of coal plants as well as displacements of some of the coal business. We also expect the small amount of industrial demand growth to occur rather that what we’ve seen over historical years.
It’s also important to note that we also believe that natural gas will have a more prominent role going forward as they are clean burning fossil fuel in the US Energy Policy.
Please flip to next slide. The chart on the right here kind of shows the plan, the coal retirement and where they are located, you can see most of them move to the eastern side of the country. Demand growth there will primarily driven again by the electric generation demand as well as industrial demand. We see the prospective coal displacements to continue. And that chart on the right kind of gives you a cumulative picture in the red bars as to how many expire by 2030.
Now we’ve already seen it and that probably has helped our industry quite a bit over the last year. And I think 2011 versus 2012, electric generation demand growth was about 5 bcf a day and most of that came with the expense of the coal retirements.
This next slide, given all the activity in the rich basins that we’re all familiar with the Eagle Ford, the Granite Wash, the Cana, the Marcellus, we’re projecting NGL production growth to grow at almost 4 million barrels a day by 2025. And again, all this is being driven by the technological advances of horizontal drilling, the multi-stage fracturing we take into these rich plays and is continuing to develop.
This projected growth is going to come primarily from the Liberian product, products namely ethane and propane. And because of this excess supply and we’ll cover this here in a moment we’re expecting some bearish prices as it relates to essaying much to the most part as well as some propane effect.
We’ve also starting to see significant ethane rejection especially in the mid-continent and the Rockies. I think December production was down roughly 10%. Some people are estimating 200,000 barrels a day is the highest, 250,000 barrels a day, and that’s probably going to continue for at least some time period.
Ethane I think averaged roughly $0.24 a gallon in December gas was $3.35, which is almost parity. So we would expect that to kind of continue here for some time period as a lot of this NGLs are continuing to be developed and arrive all right with the even tumbling market.
So, let’s move on to slide 6, this chart, the upper part of this chart, the red line, indicates the projected ethane supplies over the next number of years. And then stats below that in the bars is the projected ethylene cracking capabilities. So the baseline is the blue line you’ll see in the chart. And then well also shown on here the expansions are occurring in the green bar as well as other plants have come out of retirement along with Canadian cracking capabilities.
But then in the far below, in this table in the lower part of the chart, we’re showing what we consider to be the high grade new cracking capacity and when it’s coming on. And so, that’s represented in the purple bars on the upper chart. So what we’re expecting is this added pressure on ethane prices is due to the over-supply position that occur probably until somewhere mid-decade 2015, 2016 until these new crackers come online. So, this distributes all these bearish until that timeframe.
The good thing is these are all located in most of the pet-chems are located in Mount Belleview where they have access to all this NGL supply is being developed and the pipes drilled pointed towards the same part of the world.
If you go to slide 7 please, this chart on the left side represents the forecasted propane supplies that are being developed. The chart on the right is more the forecast propane demand. The left side is a result of the continued drilling of these rich gas plains that we talked about and that are generating large amounts of propane.
In addition, on the right side, the forecasted demand is a result – and this growth in demand is a result mostly of the export terminals that are coming online by enterprise which there are some billing that’s already on to some extent and export in propane of the country, probably not at max capacity yet. And as well as target has another one slated to come on I think in the third quarter of – later this year.
This does not include the – I believe I’m fairly starting this chart doesn’t include some of the other ones that are being talked about, I think Aussie has a facility they talked about bringing on a river side or Eagle side in your corporate and there are a couple of others that have been talked about. So, but that’s right here, these two expansions alone bring out roughly 150,000 barrels a day, all told between them which will help significantly move some of the propane out in the market.
So, first we’re going to take a few moments to talk about forward curves and if you’re all – those listening on the webcast this does not apply to you but I believe your presentation for you folks out in the audience there, the chart on your – the access on the gas line, you’ll see where it shows $4, the upper line shows $4 and there is another line underneath that that shows $4, that lower $4 should be $3.50. So, it’s just – it’s not – I believe I can make that correct, okay.
So, as you can see the left slot shows our forecast of NGL of getting natural gas prices along with the forward curve and the EI, I’m sorry and the EIA. And you can see natural gas, we’re very fairly well aligned and what we believe the price are going to be going forward and they’re all very well aligned with the forward curve as well.
A couple of things to note, we have a very bullish view on for the long-term view of commodity prices due to the robust demand growth. Now the chart on the right also indicates we do not necessarily believe that there is high oil to gas ratio, in terms of pricing it will continue and that has been, but will still result in favorable economics going forward just not to the extent we’ve been seeing in this current timeframe. So, we’re still bullish about processing margins over the long term.
If we go to slide 9, it gives a fundamental view of the robust forecasted commodity price outlook. We believe our bad gas business is well positioned to capture as commodity prices return. Our operational excellence, our system integrity and safety of our top priorities and found again from which we can grow our business. We continue to make significant investments in the gas business as well to ensure our system integrity and to keep our systems safe.
We are focused on optimizing our gas assets and then this also includes expanding our processing facilities. We are currently bringing on the AGX plant, approximately to be coincide with the start of the Texas Express in the end of July, I believe is our latest timeline on bringing that plant on as well as Texas Express.
We also are continuously looking and prioritizing, optimizing the value of our NGL barrel and our condensate barrels for both us as well as our customers. And we continue to pursue I think somebody mentioned earlier fee-based business, anytime to represent itself which we didn’t, our most recent big scale project up in the Haynesville with demand based contracts and all of that being fee-based.
So, if you would please move on to slide 10. Here we present a broad overview of our natural gas positions in the three major basins in which we do our business. You’ll recognize them as being in East Texas, the Barnett Shale of North Texas and the mid-continent. And allow these, we tend to throw call this like the mid-continent Granite Wash play but it goes well beyond the Granite Wash, the Granite Wash, it’s the Telco Wash, the Hog Shooter, it’s all these multiple horizon that provides different opportunities that these producers drill through these formations even the time in the future right, at some point in time when they come back these are the formations.
In addition, we have the same thing going on in the Barnett Shale, it’s not just the Barnett, it’s the Glamour, it’s the multiple falls, and all these multiple formations where activity goes on. And East Texas is the same thing, it’s probably the most – by far is the most large scale of all of them has got multiple formations as well that provide opportunities for customers.
We also expect our investment in Texas Express mainline and the Texas Express gathering that contributes significant contributor to our business going forward.
If you’ll go on to slide 11, our Anadarko System is situated in the mid-continent including our recent acquisition in like 2010 of the Oak City asset. And we made significant investments in this region in the last number of years as you all are probably aware. Most recently we upgraded the Sweetwater Plant and Allison Plant to be able to handle the higher GPM gas withstanding evasions. As you kind of heard some of the press about the Hog Shooter and that’s been probably the most aggressively pursued formation in recent times because of the high condensate volume the producers are finding, along goes with that this goes the higher GPM of gas. We’re seeing routinely wells of 5 GPM to 7 GPM gas and sometimes even higher on some instances. So that’s one of the reasons why we upgraded the plant.
In addition, we brought on our Allison Plant in April of 2012, 150 million a day facility and that’s been running loaded almost since the day we ran it. Our AGX plant as I mentioned would be coming up later this year. And it’s also 150 million a day plant slated for roughly 15,000 barrels a day of capacity as well. This also twin – associated twin to the Allison Plant.
All of these, all provinces, all these regions we’re seeing the same type of GPM gas, is all but it varies with the formations. Different formations have different qualities. But in general that’s a good frame roughly 5 GPM to 7 GPM gases at decent number on average.
In addition, we are enhancing our competitive position with the construction of the Texas Express NGL pipeline. We’re partnering it up with three very good partners, Enterprise, Anadarko and DCP Midstream. And this will help us provide added value – added piece of the value-chain for our business as well as our customers providing access to Mount Belleview which is very important over the long-term.
And the difference about Texas Express as opposed to some of the other projects that are out there is that this project will – because of its connectivity with Enterprise, we’ll be able to provide access to South Texas, the Permian, the Rockies, the mid-continent, etcetera so that’s why we’re very excited about this pipeline as it really diversifies in a number of producing basins.
If you would turn to please – slide 12. As I mentioned our East Texas system is our largest footprint by far. It’s – we’ve had a lot of high productive dry gas wells were drilled in the last couple of years as the Haynesville was being explored in that area as well as the Belleview. And we’ve developed a lot of significant on-system markets as well as intra-state, inter-state connectivity that we never had over the last – number of five years or so, so that now it’s actually an optionality in different points, where the customers really want to go.
And the thing is, probably into this last year we saw roughly a 10% to 15% decline is some of that dry gas filling dried off but our forecast for this coming year is we expect our process buy-ins which have stayed flat for a number of years and our NGL production as well to be flat as well, we’re not expecting a decline there.
We’re also very excited about the number of emerging Shale plays and an unconventional play as well. The Cotton Valley is being actively explored, the horizontal drilling as well as this fracturing technique. And it lies in the heart of all of our existing footprints and we’re seeing some very promising results there. And there is a significant amount of activity related to the Eagle Ford which is quite frankly commonly believed to branch up into this area as well, along with the wood buy-in which is more of a oily type of formation, the Eagle Ford being more of a gassy – not gassy but more gassy than Eagle Ford so, other than the wood buy-in.
So all these are very promising it’s all in the reach of our system. And we think as well with our optionality, with our market access and the ability to move NGLs it will be a by large growth opportunities for us going forward.
If you could move on slide 13 please. Okay, our North Texas assets also reside in the Barnett Shale. We’ve seen a lot of continued drilling for the Barnett and also some expected continued drilling in the Marble Falls which has more been a lily type play but has the significant amount of associated gas with it. So, we’ve seen our NGL volumes have stayed flat over the last year. I actually have grown a little bit. And so that’s been a nice little area for us to continue to be in.
Another thing we’re doing is probably we’re focusing on optimizing the value of our liquids and remembering that this group of assets for the most part will also be in the Texas Express when it comes online later this year, with accepting I think one of our plants will not be until next year.
But still, what we’re doing out here, we’ve been stalled and expand our condensate stabilization facility at our Spring Town plant which enhances the value of condensate for us. We’ll also bring some third party business into there – into that facility as well.
Please turn to slide 14. Okay the partnership is also positioned to expand this natural gas business by pursuing low risk logistics growth opportunities. Say that three times fast. We – I missed, we fully – we just recently expanded the Spring Town stabilizer to 4,000 barrels a day and we required that plants to expand it by another couple thousand barrels a day.
We also do third party businesses at this facility, bringing some trucks from our affiliates ELTM, Enbridge Liquids Transportation and Marketing and through other affiliates and generally do marketing to bring third party condensate both high – what we would call hot condensate which is higher at the vapors as well as condensate for stabilization.
In addition we have another 5,000 to 6,000 barrels a day, located in the Pan Handle as well in North Texas of stabilization capacity. But we don’t currently conduct any third party business today but we have plans that kind of goes in that – goes into that and enhance that for other third party business later on this year and probably plays into later this year and ultimately grow that.
In addition our AGX facility has a 2,000 barrel a day stabilizer that will be coming on when that plant comes on as well. And we’re also looking way to maybe expedite that one coming a little bit earlier.
The partnership also recently brought into service a rail facility in Pampa Texas where we take basically bring in and condensate by trucks and I’ll trial it to market to get ultimately enhance our price for condensate in the region. We’re also looking we’re doing third party business for that facility through our EE marketing affiliates.
Our NGL trucking and logistics business sets the partnership up to provide seamless and bundled service to our customers and the group also manages 150 railcars just for the partnership alone.
Our natural gas marketing business continues to function, provide patenting of our natural gas to the right points to get the gas to the right market. And it’s still back to back origination opportunity.
If you please move to slide 13, as Mark and Steve discussed earlier in their respective presentations, we also have focused on integrity and system and achieving top tier performance as it relates to risk management and integrity. The partnership encompasses internal and external benchmarking for practices of cost, and we’ve established due diligence integrity protocol for all of our new – potential new acquisitions.
We also continue to look at emergency flow restriction devices to protect high consequence areas and some of our leading best practices include chemical inhibition, maintenance pigging, consolidate protection, signage, public awareness programs and patrol.
We have also improved our safety culture both in the field and in the office with an added intensity of I don’t know how to express it other than we really tried and gotten everybody involved in it, all the way across the company and even feel a lot in the Houston office and so we’re really focused on that as well.
In closing, if you move on the slide 16, as I mentioned operational excellence, system integrity and safety are our top priorities as we look to form that foundation to grow our business, provide reliable services to our customers. This is going to be our top priority for our team and has been and will continue to be. We have a great solid portfolio of assets or continued to be adequately forward in the regions I mentioned and we’re quite excited about that. And we expect that to continue because of the nature of the risk plays, they are located in rich processing plays.
And we also focus on optimizing our natural gas, that’s most of the stabilization facilities that we talked about, enhancing our plants and looking to expand plants and provide access to our customers – the premium mortgage like Mount Belleview and things like that.
Are there any questions?
I guess, it’s first on the – couple of questions on the condensate logistics, mainly at Pampa you’ve got the rail facility. I guess first is that, right now just moving your own equity barrels. What are you moving right now onto rail and what kind of net back improvement are you getting there on your condensate?
I don’t – I don’t know if we’re – I think today is roughly 2,500 I should have said this, I’m sorry, 2,500 barrels a day capacity it was permitted for today. And I think we’re pretty close to utilizing all that. We also have plans underway to expand that – we have the 25,000 barrels a day, ultimately with a air-permit that we could have possibly get to 60,000 barrels a day.
There is also a significant amount of storage on location, training capabilities. And I’m not sure about the – really we’re doing it as a fee based business in terms of us, I’m not sure how much – I don’t know if you can speak to it, I don’t know the exact number. I’m sorry, you asked the question about we move our own products through there as well as third party business.
So, the 25,000 to 60,000 barrel a day capability that would involve third party volumes?
Oh yes, yes, yes, absolutely.
Okay. So, I mean, do you have your own trucks right now, I mean, you envision in building rack loading capabilities?
It already has trans loading capabilities already but not necessarily to go to 60,000 barrels or 25,000 barrels a day but that’s part of the potential expansion we’re talking about. And yes we do have our own trucks, it’s all – everything is being truck there. It might be that everything going through there is being trucked in today. And but – and I think most of those are our trucks that are bringing in, there may be some third party trucks but I don’t know there is very many. Our trucks bringing third party barrels and our own barrels right, and then some third party, yeah.
Winfried Freuhauf – W Fruehauf Consulting Limited
Winfried Freuhauf, I have a two part question on your slide 3. The first part is, if one accepts the EI demand forecast. How do you see implications of this demand forecast for Canadian imports of natural gas or US imports of natural gas from Canada?
I think we would expect Canadian ports to drop given where the Marcellus is expected to grow and that’s where all the Canadian ports would come into, if that’s what you are asking, yeah. Because the other thing, couple of end of this, so there is going to be some amount of LNG export as well, so how much that impacts is probably too earlier to call how much that’s going to impact Canadian imports?
Winfried Freuhauf – W Fruehauf Consulting Limited
You wouldn’t have any estimate on how much Canadian exports would – might drop between now and 2025?
I don’t, I don’t have that now.
Winfried Freuhauf – W Fruehauf Consulting Limited
Second part is on still the same slide, you mentioned and also Mark mentioned coal displacement for electricity generation. When I look at this demand slide for electricity, it looks fairly flat and doesn’t seem to be all that much replacement of coal by natural gas between now and 2025?
No, it’s not – you’re right it’s not a significant growth number within there. It’s probably a bit conservative in terms of because this study is the EIA’s forecast. But I would say that we would have been through our own forecast, I would expect the power generation number to be higher than what the government is forecasting.
Winfried Freuhauf – W Fruehauf Consulting Limited
How much higher?
Well, if you kind of go back to this slide here for 2013, there is roughly 15 giga watts of coal that’s been retired, for 2012 it was at 8, right. There was 8 giga watts when we retired in 2012 approximately. And like I said, the gas consumption related to electric demand was up 5 bcf a day now all that was retirement, some of that was displacement, some of that was just weather and things like that. So, if you’re expecting in – this 60 giga watts for now, that’s six times that much, roughly 8 times that much that would indicate that it was all displaced by natural gas which it won’t be – that would be roughly in that time – in that ballpark. It’s a significant number it is all displaced by gas.
Yeah, I just had a simple question. You indicated that the production volumes in North Texas I guess dropped 10% to 15% or something?
That was East Texas.
East, okay, that’s my question on East Texas is, are you expecting it now to be stable in East Texas, you’re indicating North Texas was stable?
Okay. Here is kind of when I talk about volumes, East Texas we’re expecting a slight drop, it was really pretty stable for 2013 for natural gas. We expect our processing volumes to be flat as well as or NGL production numbers to be flat in these sectors.
As for North Texas, what we have is a – is really diversified, we’ve got East Texas and North Texas both are diversified. They’ve got dry gas and we’ve got rich gas. And they are segregated in parts of the system. In North Texas we did see a decline somewhat in the dry gas side of the system but our rich gas elevated somewhat I don’t remember the numbers exactly. And that’s why our NGL productions stay pretty close to flat in 2011 and 2012, and that’s because the rich gas drilling continues to be explored, does that answer your question?
Yeah. And the gas production you’re also expecting to net out being roughly flat?
I believe that’s correct. I think from 2012 through 2013 roughly flat, yeah.
Can you comment on the scenario of the prolonged rejection environment, what the impact would be to your processing business?
Well, it would be – have a continued negative effect on our earnings because I mean, we were counting on. Now in 2013, we were counting a lot of it and rejection for the entire year for the midcontinent. I mean, that’s been our forecast. As it relates, if you goes beyond that into other regions it’s going to – I mean, that would indicate a lot more pressure on NGL prices, or upward pressure on gas prices, right.
So, I think we’re roughly 70% hedged for this coming year, approximately probably to the 40% to 50% next year and prolonged, I don’t know if it’s – if you mean prolonged beyond that – it would continue to have a somewhat effect on – I don’t know the exact number, I don’t think we run through that.
On prospective new gathering and processing facilities, what would be the nature of your contractual relationship with producers, would it be exclusively fee – to what extent would you take a risk exposure on volumes or prices?
We’re really increasingly pushing towards – the new plants that they were considering investing in and would it be – say in East Texas to other areas to do a fee based type transaction. But generally speaking it would probably be a combination of fee and commodity exposure type of agreements just because that’s probably was going to be pliable on both sides of the arena.
Also we’re going to be pushing fairly hard to do demand base, at least volume type of guarantees in those areas as well. Whether or not we’re going to be able to get that – it’s hard to say just because it is compared – everyone in this basin is extremely competitive. There is a lot of people talking about capacity and expansions and things like that. But yeah, I’d say right now that’s what we’re approaching for and what we’re looking to get to. Thank you.
Good morning. My name is Steve Neyland, I’m the Vice President of Finance for Enbridge Energy Partners. I’m pleased to be with you here in New York. As we were on break, I couldn’t help a reflect the throngs and people surrounded Steve Wuori that this is what it would be like to – be the roadie with Bon Jovi or Paul McCartney or one of those people. So, I had a fainting blush with greatness there, I just wanted to share with you.
As far as key messages that I want to push across to you today and hope that you graft associate with this presentation is the attractive value proposition of the partnership, Steve and John and Mark talked extensively about that and I want to hopefully bring that port also.
Additionally, our distribution growth is supported by these attractive liquids projects in excess of $7 billion announced in 2012, so significant. Additionally the way that we’re going to bring these into service is through a manageable financing plan. And then finally as you’ve heard – noted today and I’ll bring forward a couple of times is a very supportive general partner in Enbridge Inc, not only as it relates to the ability to facilitate our financing but also as it relates to our strategy. And additionally we’ve talked about how they come into play as it relates to future drop down opportunities. So, we’re certainly advantaged as an MLP to have a parent such as Enbridge.
Distribution growth target Mark also touched on this slide, again, six years of history. And important to note here, in the financing section because it relays into our financing plan that we’re looking to achieve at 2% to 5% distribution growth target. And again as these projects come into service we’ll look to be at the higher end of this metric.
So, how do we integrate these projects and we think about them as the company. We’ll go through a set of investment criteria and we take pain staking process as it relates to looking at all the different risks associated with different projects, so whether that’s client risk, whether that’s construction risk, whether that’s volume risk, commodity risk and so forth and each project is unique and different.
Through that process we develop an effective democracy that drives out a risk adjusted cost of capital for us. We’ll touch on some of the returns associated with our projects but generically or typically we’d like to see those returns on a minimum basis be in the low teens.
The investment criteria is also inclusive of the LP unit holder that it is accretive to the LP unit holder in its first year of implementation. And then finally, it’s strategic. So does it either build out our existing footprint, or solve some other issue that we have as the partnership.
I think you’ve seen, obviously the strategy of the market access in the Eastern Access projects, access to markets. And enable the long-term viability of Enbridge Energy partners that fits as the meat in the sandwich between the Western Canadian oil sand, the Bakken and then these extensive market extensions that Enbridge Inc is building.
So, that investment criteria has enabled us to put forward these secured growth programs, which again predominantly liquids cost of service, take or pay contract structure, i.e., or milking the volume risk out of the business as these things come into – as these projects come into service so that that transformation occurs over time but what’s critical for us as a management team is to be able to execute.
So the table has been well set associated with projects that enhance our future earnings. But for us it’s execution. Steve talked about the major projects group and the success that we’ve had there as demonstrated in this slide is on-time and on-budget. And in my presentation I’ll touch on the financing execution which is also certainly critical for brining this project in this service.
Here is the capital forecast, the component on the left you’ve seen before in our Analyst presentation we did approximately a month ago when we provided guidance. To the right we’ve sliced it up a little bit differently to show that the components of the spending that will be occurring over this time period. Again this is a net capital forecast so it’s net of an assumed 40% ownership and our Eastern Access and market extension projects.
Moving from the bottom of the $4.8 billion that is the remainder, that is, left to be spent associated with these secured growth projects. Additionally the $2 billion I’ll spend just a moment on that. It’s a mix of growth projects both in our gas business and our liquids business. Those would be things such as tankage along the main line through our FSM surcharge. Tankage at Cushing, well connects for our gas business, additional compression and our gas business in aspects such as this. Additionally there is a component of integrity spending that is also capital in nature which I’ll spend a few moments on as we move through the presentation, and I’ll get that at the back end and finally maintenance capital.
All in, we’re looking in at about $7.4 billion capital program on an additive basis. So, that’s also in front of us. And our job that I hope to talk to you about here today is how we plan to execute on that financial plan around it.
So, moving to the next slide, slide 6, this is a pretty powerful slide. If I can – because it speaks to the metrics around these projects. If I can draw you right at the left side of the slide you see the break between our liquids business which is certainly the driver of this capital we’re putting forward. And then more modestly we have expansion and growth on the gas side of the business, coming to approximately $5.6 billion.
Those amounts are net again of (inaudible) so was a 40% ownership in these of the different returns on these projects, these are good solid returns from an EBITDA multiple standpoint. Obviously they vary depending upon a lot of factors, competition as well as when we’re doing these market expansions are we twining the pipeline or are we just putting pump stations and additional tankage on them. So obviously the – if you’re just powering them up it’s more cost effectively capital is being used and you’ll typically see a better return in those circumstances.
Moving all the way to the right on the slide is we’ve demonstrated with the large green checkmarks is the cost of service or shipper pay contract structures, these are critical. So it’s not just that we’re putting projects into place or the type of projects we’re putting to place. So you will notice there are more green checkmarks than the triangles and additionally the ones that have the green checkmarks are the largest dollars on the page.
So, what you’re seeing here is effectively a transformation of the revenue stream construct for the partnership. And if I take you to slide 7, Mark Maki, slide with the ribbon chart so we had to recreate one, it looks kind of like it’s sitting with circles here. And this shows is effectively, it’s the same slide that Mark had, so if you’re trying to tie the numbers at home that they do tie is – what it’s doing is from 2008 until 2006, that blue wedge – that cost to service or shipper pay component moves from 18% to 60%. It is on a 100% basis, it ignores the joint funding. But the partnership as a whole is having a significant step change as it relates to the type of commercial contract structures that are in place.
So, we’re very excited about this and we’re going to move to a lower – a component of risk as it relates to the partnership. And you look back, whether how long you’ve been following the partnership whether it’s two years or 10, some of the things that snuck up on us have been volume risk, the speed with which the Canadian oil sands develops, volatility in the commodity space. And we will still have that as a partnership but relative to other MLPs, it will be much less significant relative to our peers.
Moving on to slide 8, this is just a quick graphical representation of our growing Bcf as these projects latter in the service. Again these are 100% ownership assumption numbers. But what you can see is 2013 and 2014 you get a moderate amount of growth in 2013, we’ve got the Bakken expansion project that Steve Wuori talked about that just a few days ago we did a press release on.
In April we have a line 5 coming into service. Mid-year we have Texas Express and our AGX system coming into service, all those help. They are coming in throughout components in the year. And then in 2014 you have certainly the big boy in the room will be Eastern Access coming into service and that’s the replacement of 6B. And then those cash flows begin to increase even further as this capital begins to generate cash flow.
So, transitioning from ‘08 to ‘09, these projects come into service. And as mentioned we – in the near term it’s a challenge because we have to finance these projects that are not yet spending off that cash flow. We do see it coming around the corner as it relates to 2013 and 2014 but in the near term it’s put pressure on our coverage metrics. A reminder here that this coverage metric includes – the footnote at the bottom includes our iShares so you have about $90 million or so of paid-in-kind distributions that are included, different MLPs will show this in different way so I wanted to note that we’re showing it the most conservative way.
But the kicker here is the direction of the aero. And our confidence that the coverage ratio here improves as these projects come into service. We’re confident because why, one, it’s mathematical. Secondly it’s the execution that we talked about – execution from the major project standpoint and the execution from a financing plan standpoint. So, as these come into service, we’ll get back to our 1.05, 1.1 target that we have. Additionally we’ve been through periods before of strained credit metric and coverage ratios, not a place we enjoy being. It’s not our long-term plan. But given the slate of growth projects and their significance it’s created this near term challenge for us. Longer term and again I’ve noted the projects coming into service just in the next several months, those things begin to improve and we work towards that higher end.
So, I’ll just leave that again with our high level of confidence associated with that trajectory. Similarly on slide 10, these are a couple of our credit metrics, our leverage metric and FFO to interest. On a debt to EBITDA we’re at the higher end of that ratio and again we see it coming back down as these projects latter in the service over the coming years.
And also to note that credit metrics are extremely important to us. And I don’t want to – we do not take our investment grade credit rating for Granite, it’s something we have to keep an eye on. As Mark noted, it’s certainly a focus of us as a management team and we’ll continue to do what it takes to maintain our investment grade credit rating.
So one of the ways where we’ve been ensuring that investment grade credit rating, creating more enhanced flexibility from a financing standpoint, it’s through our joint funding agreements with Enbridge Inc.
So, when this massive slate of projects was upon us, we recognized that this was a lot of capital consumed. Our management team, our independent board of directors and Enbridge Inc worked to put in place a joint funding agreement that effectively provides Enbridge Energy Partners with the ability to option down our ownership interest and draw your eye to the right side, the Eastern Access US mainline projects, $4.8 billion on a 100% basis, we own 40%, $1.9 billion.
It gives us the ability to option down to 25%, and/or option up later in the process after one year from in-service data these projects. So that’s $700 million plus option that we hold as the partnership. We hold that until the June timeframe. And we’ll exercise that option judiciously and with a lot of thought as it relates to lot of factors to consider what the markets are doing, other opportunities for the partnership as well as just being disciplined in our financing.
The thing, we’ve talked about this before but just to emphasize it, these projects, we would love to have 100% of them, it’s just that when you look at the financing aspects associated with it, it will be very, very difficult on the partnership. Longer term, it’s a natural drop-down candidate. It’s effectively it would be really seen once to drop these down in the longer term.
So moving to slide 12, this is our liquidity position. Key here again, schematically it’s flexibility. We have $3.1 billion in credit facility capacity, which we recently upsized thanks to Darren Yaworsky and his team in Treasury.
On a pro forma basis when you look at year end liquidity, we’re about $2 billion, we take our $1.5 billion and add the additional credit facilities we put in place. That extensive amount of liquidity is important to us. We want to be able to continue to run our business and fund our business and pay for these projects, if in effects we had some type of market shock like 2008 time period and we’re able to go a full year without having access public markets, that’s what we try. And I run with it as it relates to our credit facilities, obviously the ads and flows but in general that’s our target.
And finally, again as it relates to flexibility we have a lot of tools that are at disposal around how we go and raise that debt and equity. Again just to touch on, we target a 50-50 debt to equity ratio, nothing is changing there. We continue to standby that. And we know that that’s critical also as it relates to achieving investment grade credit ratings staying true to that.
So, if I draw your eye down the left side, the couple of blue boxes there debt and equity, different options. We want to be able to think creatively. We have hybrids up there, something we’ve done in the past. It would be something we would consider again. At the end of the day it’s about discounts and level of access to capital that comes into play. But we’re also very pleased with our recent EEQ offering that we’ve done for $270 million that was something we’ve been looking to execute on for a while. And so I think that just demonstrates the level of flexibility of the partnership from a financing perspective.
So, before leaving the slides, so just I know you have it but we talked about the three levels of flexibility, the joint funding agreement in excess of $700 million. We talked about $3 billion of credit capacity, and here we’ve talked about all the different tools we have at our disposal in order to go and raise that equity or debt with – obviously consistent with our investment grade credit rating, it gives us a lot of optionality.
Derisking the business through our hedging program, John Loiacono touched a little bit on this. This shows, when you just look at our business just from a gross margin perspective on ‘13, the kind of the split between fee base and want to expose. And through our hedging program, you end up with less than 5% of your margin that’s sensitive to commodity prices.
Nothing has changed here I think for as – what’s changed a little bit I guess is we have – our liquid side of business has grown, gas side smaller so a relative risk is a bit smaller than we talked about this last year. But we continue to be naturally hedged as it relates to our natural gas business. We’re sure as it relates to feel in shrink in the plant, we’re long as it relates to our POP and POL contract structures. And that’s effectively next to zero or close to it.
But we do have sensitivities on the MGLs and we saw a lot of that last year with ourselves and the others hurt by that. We are in excess of 70% hedged at this point. When we did our guidance we used a mid-January price point for the forwards and what the experts saw at that time. And prices are relatively consistent with that. But we feel like we’re in good position as it relates to 2013, the guidance we’ve put forward and we’ll continue to focus on what does the board mandate at hedging program, when you hedge 70% in the first 12 months, we hedge 50% in the second 12 months. So it’s not optionality that we have around that – we do have some levels of management discretion. But we’ll continue to hedge and we’ll continue to lower the risk of the business.
Slide 15, speaks to the integrity program and the size of the integrity program spend. On the far right, the blue box represents – Steve showed a lot of our in-line inspection tools upon his chart and run those through the pipeline we determined whether it’s different issues or potential defects, when we go out there – we dig them up. We replace the pipe, we sleeve the pipe potentially we coat the pipe.
Those programs are capital in nature. We’ve been very busy associated with them. When they happen we record them to our capital. If you’re running an in-line inspection that would be an operating expense.
After we’ve done that – on an annual basis, we file our tolls and when we file our tolls with our shippers on the lake head system, we go to a process, annually where we have a discussion with our shippers as to what’s recoverable under our various cost of service mechanisms that we have. And to some extent they were recoverable through those cost of service mechanisms and to some extent they are not. If they are not, then effectively you’re just receiving that payment through the index toll that exists which is the PPI plus 2.65 on our tolls. So, that’s the process I go through on an annual basis. It’s hard to forecast what that recovery split is, generally it’s been around the 50-50 type number.
To the left, just as importantly is the level spend that we’ve had in Steve Wuori mentioned a blitz and being very aggressive associated with this program which is true. The numbers certainly bear that out as you look at ‘11, ‘12 than what would project for ‘13 from the spending standpoint. However as we look over the next hill, we see that coming off.
Couple of reasons, one, we blitzed it and we’re going to go back to more normal or regimented cycle of – whether it’s two-years or five-year inspection periods for different IRI runs, as well as the fact that the 6B pipeline which is a tape coded line, which has been a large component of the integrity spend will be replaced. So that will be helpful. And so, certainly the pin-code aligns have been a challenge for us from an integrity standpoint, so the fewer of those you have – the lower your integrity program costs.
Slide 16, this is our financial outlook. You’ve seen it before. It’s consistent with what we provided a month ago. I’m not going to go over it other than to just say mid-point there is $1.3 billion and EBITDA for 2013. And we remain confident associated with that projection.
As far as key messages, our long term outlook is very strong. We’ve secured $7 billion – in excess of $7 billion of growth, which lowers our risk. And through our structure and through our processes – we are well positioned to execute and we’re confident in that execution of these projects both from construction, in-service timing as well as financing.
So, with that I’ll take any questions.
Thanks. Actually couple of quick ones, I hope they are quick. Is it a fair takeaway that the reason why the integrity expense is now shown as maintenance CapEx is because it goes back into some of the rate structures you get so therefore you get money off a bit and it’s not a clear outflow?
That’s correct. You’re right on there is that – to the extent you’re not receiving that return and you need to look at it in a different way so you could hit it.
Okay. And then the second question, I was wondering if you could just – from almost a theoretical standpoint, now that you would be looking for the capital markets, especially start focus on the debt market right now to help finance this growth and starting in about I guess 40 years, about $0.5 billion a year that need to be refinanced.
How do you go about thinking about the trade-off between take in short term paper with the artificially low short-term rates right now and saving cash versus on the same hand locking in lower historical rates for a much longer term and trying to push out your debt for as far as you can, knowing that – five years plus, we’ll be looking at a couple of hundreds basis points probably higher. And over your life along you’ll probably be saving money?
Right. So, my – well, first of all obviously it’s stretcher below and we will continue to be judicious and resist the temptation to load up on all those very cheap debt that exists in the marketplace. And we do have some refinancing that are out there, $200 million a year over the next couple of years.
As we think about where we – the term of that debt that we put into place – we’re going to look at these – this chart on ‘13, which shows our maturity windows that we’re looking to hit. And so, when we think about – we do a 10-year or a 30-year and what’s appropriate, it certainly will look at where the market is. But additionally I think hitting these windows are going to be just as important. As we’re planning for the long term aspect of the partnership and at some point we have to refinance this, it will be some other guy stand up here and talking about that – 20 years from now. But we recognized that that’s an important aspect. So hope that answered your question. Yes sir.
Winfried Freuhauf – W Fruehauf Consulting Limited
Winfried Freuhauf, I have a couple of questions. The first one is, what were the unfounded pension and other benefit liabilities of EEP at the end of 2011 and 2012. And how does EEP propose to deal with the funding of these unfounded liabilities?
Right. Okay, well, first of all just from a pension liability standpoint is that the way the partnership works is, technically all the employees within the partnership work for Enbridge so there is a pension plan that sits underneath Enbridge which the EEP employees are beneficiaries of that pension plan. So it’s managed at Enbridge Inc level.
However we do, at the management team of the partnership does have insight into that pension plan. So, like a lot of pension plans with discount rates dropping off the cliff, and jacking up those liabilities it’s challenged certainly every pension plan in America, so we’re no different than that. Other than that we are – we are relatively well funded and we also take a more aggressive funding policy than is required by the regulators. So when you look at where we are relative to what’s required, we’re in excess of that. We are slightly under-funded I don’t have the number on the top of my mind associated with that. But relative to our peers we’re significantly better funded.
Winfried Freuhauf – W Fruehauf Consulting Limited
The other question I have is on your slide 6. And the question is would you have earnings multiples instead of – in addition to the EBITDA multiples?
Yeah, we’ve chosen to provide the EBITDA multiples rather than the own use multiple. Your thing might just return on ROE, or DCF ROE type numbers. And typically we have just talked in general about that. trying to walk the line we’re providing enough information for the investor, yet also knowing that there is also competitive aspects associated with the information that we provide. So, probably we’ll continue probably to shy away from that other than they talk about returns, in a general context as I mentioned earlier, we’re looking at achieve these, these low teens type of returns.
Winfried Freuhauf – W Fruehauf Consulting Limited
The other question I have is, this morning Steve mentioned that it is hard not to love end brakes. If each one had EEP, if one had bought EPN it’s the year ago – almost exactly a year ago and compared the price then with the price no one has clearly experienced and exercised and tough luck and tough love. And my question really is, when one looks at the deteriorating metrics financial metrics that our annual presentation. Where do you think you will be in 2013, this is on slide 15 I believe? And I should add that on slide 19, I should add that I’m assuming that while they are external forces affecting the unit price, a lot must drive on these deteriorating financial metric.
Right. So, as you look at 2012, two challenges primarily in our 2012 numbers. Number one, as mentioned, we’re pre-funding for these projects and are in service, those projects are just starting to come into service and will scale up. The other piece associated with that in 2012 was NGL prices. They – with a 40% plus move on NGL prices in a period of one month, that’s stung us for approximately $70 million in 2012. Those NGL prices have and sensed have not really recovered. And so that’s a challenge, as it relates to the partnership. So you think about some of those near-term challenges, those are a couple of them. But they remediated through these projects coming into service. So it’s not lost on us, these credit metrics are not where we like them to be, but also what’s the expected trend in our confidence in that trend is high that will be improving.
Winfried Freuhauf – W Fruehauf Consulting Limited
I seem to recall at the 2012 EEP Meeting, EEP sort of prided itself on pursuing liquids with gas, and I don’t hear the same product this time around. So, were you optimistic of your goal?
So, we’re still excited about the liquids rich gas plays that are there to the best John that jumped up and down a little bit more maybe. But in the Granite Wash area and our Anadarko system it’s significant access to how Hog Shooter and these other formations. And people are still excited about that, we’re still seeing good activity associated with it. I think it’s not as maybe exciting as it was, it still is. But NGL prices have come off to some extent. So that’s tapered a little bit of the excitement but we’re still seeing growth around our assets and we’re still excited about it. And we’ll continue to pursue opportunities in and around the Anadarko area.
Yeah, hi, Sunil (inaudible) from Citigroup. I just wanted to go back to your slide 15 on the liquids integrity spends. And I was wondering what would be the new normalized level of spend, ‘15, ‘16 onwards? And then kind of a follow-up on that how does it helps you in terms of loading the OpEx, having spent all this capital upfront in the last three years again going forward in ‘15 or ‘16?
Sure. So, unfortunately I’ll be a little bit vague associated with this is, we’re continually reassessing this. As a matter of fact, we’re in the process of doing our long-range planning for the next several years. And this is a component that we look at. So as it relates to hard number on 2014 and 2015, really can’t get one under other than the say directionally it’s going to be coming off.
The footnote at the bottom of the slide is interesting, strategically place there. There are factors that are unknown – what are the regulators going to require that’s new or different associated with integrity. Well, being that we’ve looked to achieve the top-end of industry leader associated with this, we would expect that it would have hopefully minimal impacts associated with certainly less than relative to our competitors as we’re running more in-line inspection tools and doing more pipeline integrity digs, over and above what they’re doing. So, we look at that in a way, a competitive advantage if you would.
The ‘14 and ‘15, I’m going to shy away from a hard number other than to say that we expect it to be lower. And the other component of the question, I think was around operating costs on integrity. And ballpark on the liquid side of our business, we’re spending around $30 million a year and in-line inspection runs for the partnership. That number has been fairly consistent over the last two years. We’re expecting that type of number in 2013. And again that would also be expected to be directionally to head downward as it relates to the other capital side here. Terry, you want to hear.
Hi, you mentioned that you pre-funded a large floor, pre-funded some of the $7.4 billion in CapEx over the next few years. Do you have any sense or can you give us any sense for what your – how much of that has been pre-funded and what you would be looking to get into the market over various time horizons?
Yeah, so I’ll be a little bit – give you a little bit of help but maybe not all but to the extent that she would like it. One way to think about it is, between slide 5 and 6, if you compare slide 5 and I know my – couple of people probably have already done this. But if you look at the $4.8 billion out there, that’s the amount that’s expected to be spent on these capital projects between 2013 and 2016.
On the next slide, that shows total cost of projects $5.6 billion, so the difference between I would say, well there is $800 million that have already been effectively spent on these projects. So directionally that might give you some type of sense of what’s been funded. It’s not a specific answer but just kind of directional.
Jody Lurie – Janney
Go, going back to your debt maturity schedule on what is it, slide 13 please. Last year you talked about ‘15?
I lost it myself, 13.
Jody Lurie – Janney
So, last year you talked about kind of that cluster that you have in the medium term as an area to kind of address for refinancing, is that still something that you’re looking at and what sort of timeframe are we expecting on that. The second question I have is how do you account for your hybrids in terms of your leverage ratios?
Right so, on the hybrids taking the second question first. On the hybrids the flip out is a little bit different between the people which with rating agency you’re speaking. But somewhere there is equity credit, somewhere 25% or 50% depending upon the hybrid, depending on the rating agency and also depending upon on the structure of the hybrid. So that’s probably a range outcomes associated with that.
As it relates to the cluster that’s there, what it says to me as – there is refinancing embedded in here as mentioned, we’ve got a couple of hundred million dollars the next two years that will be coming off. And due – I think that comes into consideration associated with what do you do with that cluster. Typically we’ve been 10-year and 30-year type debt issuer just to say that on an historical basis. And I’ll probably just leave it at that.
Darren, do you have anything different that you would add to that or that you would like to add to that? Darren Yaworsky is our Treasurer, and I’ll see if he’s got some additional color.
I’m glad I have a mic because I have a very blooming voice. I think there is probably two elements to your question, one is how does that refinancing impact or affect our current term spend. And the second is how do we plan on refinancing once we get to that point in time?
The first part of your question is, I think maturity profile gives us enough flexibility that it doesn’t interfere with our financing requirements for our growth CapEx. What it does though is when we get into the – into those maturity ladders, our activity in the Capital is going to curtail. So there will be the – the need to continue to be active in the TCM side of things, to be able to react to those refinancings. But we have a tremendous amount of flexibility in our maturity profile.
As the gentleman suggested, back here – sir, I don’t know your name. But I think his concepts are probably pretty relevant, we thought probably to run short, go into the medium term or go into the long term. So we have a fair amount of flexibility to handle both the growth CapEx and the refinancing.
I think we’re clear. Okay, looks like we’ve cleared all the questions. So, thank you for your time.
Yeah, well, thanks everybody. Just very, very briefly, of course we’ll leave you with takeaways in the slide we’re not going to speak to that. And we’ve touched on these all throughout the day today. It’s been a very great productive morning, certainly on behalf of the management team, we absolutely appreciate the questions that everyone has offered up. I also want to thank the folks from Investor Relations, Sanjay, Jennifer and our folks from the corporate office in Calgary for all their help that they gave us here today, I very, very much appreciate it. So, if you see those folks please give them a hand.
Sanjay of course will be reaching out to everybody here to get a little bit of feedback on the presentation, things we should hit more or less or your feedback really does matter to make this a production session for you.
So, with that, I want to thank you all for your participation. And lunch is served in the conference room by the elevator back, so I’m sure you can follow the path out there. Anyway, again, everyone thank you very much for your participation today.
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