Inergy, L.P. (NRGY) Analyst Conference Call December 3, 2012 1:30 PM ET
Michael Campbell – SVP and CFO
John Sherman – Chairman and CEO
Brooks Sherman – President, Inergy
Will Moore – VP, Corporate Development
Ron Happach – SVP, Natural Gas Operations
Mitchell Dascher – President, US Salt
Bill Gautreaux – President, Inergy Services
Good afternoon everyone. I want to say thank you for attending our Inergy, Inergy Midstream Analyst Day today. Welcome to people on the webcast. My name is Mike Campbell. I am the Chief Financial Officer of the company. I am going to introduce management today. I will cover some housekeeping items. I will discuss our format and we will kick this off.
With me here in New York is John Sherman, our Chairman and CEO. Next to him is Brooks Sherman, President of Inergy. Bill Gautreaux is our President of Inergy Services. We also have Will Moore, who is our VP of Corporate Development; Ron Happach, our Senior Vice President of Natural Gas Operations; and Mitchell Dascher, who is our President of U.S. Salt. We also have other members of management team in the audience today. I think Phil Elbert, I am not sure if I have seen Laura Ozenberger today, Kent Blackford and Vince Grisell.
Before I get started with the format I would definitely want to thank members of our management team as well as people here in the room and in Kansas City for all the work that went in to pulling this together and specially Debby in the back who helped with a lot of logistics of this day. Our format, we are going to showcase and talk about the company. We are going to get our business leaders up here to talk about their specific business. We will work through the day. We will try to keep us on schedule. If there is time at the end of remarks of each business unit, we will try to field a few questions specific to that section, and if we don’t get to those questions we will allot ample time at the end of the presentation remarks to field questions that you may have.
Before we get started, I just want to cover our forward-looking statement today. In our discussions we will make forward-looking information. Various risk factors including weather, economic conditions, regulatory proceedings and commodity prices among others, may cause actual results to differ materially from our projections and estimates in these forward-looking statements. We provide a detailed discussion of these risk factors and others in our SEC filings and we would encourage you to review these filings.
So with that I am going to turn this over to John Sherman, our Chairman and CEO.
Thank you, Mike. We certainly appreciate the opportunity to be here today and thank you for coming. We are always interested in sharing our story with investors and today I think we will have some time to probe a little deeper than we normally do and specifically give you the opportunity to hear from the people running our businesses. In fact I really want you to hear more from them than from me because you hear from me a lot. These are the guys that pay the bills and make money for investors. But I have got a few comments that I want to make, really first about our strategy. The current environment in which we are operating, how we have repositioned the partnership and why I think Inergy represents or presents an opportunity for investors.
In fact I believe that Inergy presents a very compelling opportunity for investors in today's market. We have built this business with high quality assets in good markets, positioned in around developing shale plays. Income is derived primarily from fee based contracted cash flows without commodity price risk. These businesses are characterized by stable cash flows with meaningful growth potential. With our repositioning of the partnership, we have two strong balance sheets, two variable currencies and a management team that’s not only capable of executing this strategy but we feel like with a significant stake in the game and they are very aligned with you as investors. Management, active management in the company owns about 20% of Inergy wide today.
This is kind of the backdrop that we are operating in. This is a very exciting time for the industry. Dynamic changes occurring with the development of the shale plays. They are creating significant opportunities for investment in mid-stream infrastructure. Particularly, if like us you can offer flow assurance and take away alternatives for producers. We believe our focus on our producer service combined with our access to premium demand markets in gas, liquids and crude, uniquely positions us to grow effectively on behalf of investors.
You see the scope of the investment opportunity up here. The good news is that’s very significant. There is a lot of opportunity out there but I think at the same time when you have that size of an opportunity you are going to get the interest of a lot of people. We have got a large well-capitalized investors, so that’s important that you pick it, that you pick the niche in which you can be successful.
I prefer to spend my time looking forward. But I will spend just a couple of minutes backing up for a minute here and talk about how we reposition the partnership over the last year so. Last summer in 2011 we begin working on a restructuring with several objectives. One, to lower our cost to capital. We needed to make sure that we could compete and finance the growth of our rapidly growing midstream business and strengthen our balance sheet. And at the time, that really was focused on the deleveraging of NRGY. We were still in retail propane. That was becoming a tougher business, our leverage was creeping as was our equity yield.
As you can see, at fiscal 2011 year-end, we are about 43% of our EBITDA was from the retail propane business and about 57% from the midstream business. It’s actually I think probably normalized that would have been more like 50:50, that’s against the backdrop of a very warm winter. Our debt to EBITDA was about 4.6 times. Last September we filed for the spinout of Inergy Midstream and in December executed the IPO initially that was just our Northeast gas and liquids platforms. Raised about $300 million in the IPO, about $400 million in total proceeds for NRGY and NRGM, in addition to the $300 million reimbursed at Y for some CapEx.
The bottom line, we lowered our cost to capital and created a strong balance sheet to fund our midstream growth so we could continue to keep that business moving forward. As you can see and as most of you know we subsequently dropped down U.S. Salt, and in August in what was a very significant transaction, divested our retail propane business. That resulted in a massive deleveraging at NRGY, about $1.2 billion of our bonds followed and positioned the company as a pure play midstream MLP as was our objective.
Bottom line, I would just tell you that a year or more ago we laid out our objectives. We did what we said we were going to do and the propane divestiture in particular accelerated our progress. When we set out to restructure the company, we thought that it would take a number of years to further deleverage Y and really position that as a propane company which would be a balance sheet that either someone could buy or we could utilize that balance sheet to consolidate the propane industry. This is a much better result for us from my perspective. I like the propane business but I like the core business that we are in today better than the core business that we were in a year ago.
You know Ron Happach and Bill Gautreaux are going to talk and give you a deeper dive into what we do in a minute but basically we try to get between fundamental supply and premium demand markets, utilizing our assets and expertise to serve customers and make money for investors. Just a quick snapshot of our asset base. In the Northeast atop the Marcellus, we are positioned with a great platform upstream of the premium demand markets to the Northeast. We are in the Eagle Ford in Texas. Adjacent to the Eagle Ford also upstream of demand markets. Our West Coast operation is strategically located between the refining centers in Los Angeles and San Francisco. And as of Friday we expect to be in the crude oil storage and logistics business in the Bakken.
In addition to that, and you will hear from Bill Gautreaux, I think it’s a business that we haven’t had the opportunity to talk a lot about because historically it has been a smaller part of our business. It’s becoming a bigger part of our business. It’s becoming a bigger part of our business and is experiencing rapid growth. So we have overlaid all this. We have an NGL supply logistics business that operates in about 35 states and is rapidly growing.
You know this slide I think I would take a couple of things off of this slide. 70% of our 2012 business is derived from contracted revenues. Pro forma for 2013, that’s almost 80%, 78% as you can see on the slide. 30% of our business we consider to be un-contracted but I wouldn’t -- don’t take that to me in that it’s not very very stable business because it is. The rest of that business, some of our salt business is part of our Tres operation. So the other thing I would say that at 30%, maybe going forward at 80:20, I think it’s an advantage. I don’t think we would what we all like projects that we can build and get ten-year agreements on. I think that 20% gives us some real optionality to the upside that I think is an enhancement to our profile.
Mike just sent me a note here for the webcast. If people are trying to keep up with me, I am now on slide 13. Currently, as we look at our business today, we really have four stools of growth. Capital projects around our existing assets like Marc I, like Finger Lakes, like the [Copen] connector. We have dropped down acquisition opportunities by NRGM, from NRGY. Third party M&A, the Rangeland acquisition is a great example. That deal has significant upside.
I think we have described that as -- when it ramps up on its initial contracting and its initial contracted capacity, you should expect about $58 million of EBITDA. We have already got projects in the works, I mean we need to close the deal but we have got projects in the works and I think you should expect from us in 2014 more like $75 million of EBITDA from that asset with very minimal capital investment, primarily accomplished through expansion of the capacity of the rail throughput and linkage through our West Coast operations. And as well we have an organic growth in our liquids business as I just referred to a minute ago. The result of all this we think you should expect at NRGM, about 6% to 10% distribution growth from us over the foreseeable future.
Most of you know we have this dual structure, I am on slide 14. NRGY is the general partner of NRGM. We currently have business operations up there. You can expect that those will be dropped down to NRGM overtime, where the objective is to position NRGY as a GP Holdco which would own the GP and NRGM and have other financial interests in NRGM, and NRGM would really be the operating company. And you know just based on our history, I think if that’s what we are intending to do, I think you should expect that to happen sooner rather than later.
Moving to slide 15. You know you will be hearing from the management team today. Mike introduced the team. I would just tell you that we built this team with proven people with track records of achieving desired results. We have worked together across assets and our entities to make money for investors and I would mention again that I think our alignment as stakeholders should provide investors confidence as well.
Before I am going to wrap up my portion and kind of turn this over to the rest of the team, I am on slide 16, but I would just say we are focused on developing our existing businesses, getting better at what we do every day, becoming more efficient and more effective at what we do. But this is also very much a growth strategy. And again I would -- you should expect from us 6% to 10% growth in cash distributions at NRGM and than obviously the leverage to that growth rate at NRGY.
With that mike, are we going to take questions or just turn over to Brooks? With that I will turn it over to Brooks for the corporate development. Thank you.
I am on slide 18. You have seen a slide similar to this in John’s presentation, but as you know we have two MLPs and we look upon that really as two currencies for growth. Investors may also look at it as two ways to invest in Inergy. At NRGY, that’s our original MLP from our 2001 IPO. Today we own to operating businesses there. Our natural gas storage and transportation business in Texas, Tres Placios, and then our NGL supply and logistics business. We also own 56 million NRGM units as well as in the NRGM IDRs.
NRGY today has a strong flexible balance sheet and ultimately as John said, those operating businesses that are up at NRGY today will be dropped down to NRGM. And I think the balance sheet strength then of NRGY is beneficial to NRGM as one example of this is that when we drop those down, NRGY has the ability to take back a substantial number of NRGM units to also keep NRGM’s balance sheet strong. So NRGY is well positioned to be a supportive general partner as we look forward.
At NRGM we have growing businesses there also with a strong balance sheet and we are looking to maintain that strong balance sheet. At NRGM we had stable fee-based contractual cash flows with great assets in great locations. When you think of where we are located today, here in the Northeast and now as of Friday, in the Bakken.
Our M&A activity. Our focus that has been on growth oriented assets. Those assets that we have acquired have had a history of having organic growth projects that we were able to invest capital in at very high rates of return that have been helped to drive down that initial multiple that those assets were acquired at. So good assets, great locations with growth potential at NRGM and a supportive general partner.
Our capital investment strategy. I have got this slide and then I am going to turn it over to Will Moore, but just to go through a little bit on capital investment strategy. We expect to grow and we are positioned well for it today. I think the Rangeland acquisition is set to close Friday, is certainly indicative of that. Our strategy is really providing fee-based services to great customers in great locations with a quality infrastructure assets. This leads us to having those great customers and providing us than with deeper industry relationships to further our growth. We believe we are prudent in our evaluations of those opportunities while at the same time creative in our approach to that growth. Our development staff is able to make these evaluations and put us in the position for negotiated transactions which we have done time and again in our growth and we think that has enabled our growth to be that much better.
The projects you see here, the Stagecoach expansion done initially. Thomas Corners that we put into play with Steuben. The North-South, the Marc I, all of those are projects that came from acquisitions. Those projects again helped to drive down the multiple of that. And so they are examples, they are borne of original M&A transactions with those growth projects in mind as we move to acquire those assets. Expansions and new footprints. I think the COLT Hub is the latest example of that. The COLD Hub will be a very good acquisition for us. It’s a natural extension of what we already do in our NGL business. We are looking forward to having that in the fall and that as well as we have others with M&A transactions we have closed to date, the COLD Hub also has growth projects attached to it that we look to get after in the not too distant future.
And with that I will turn it over to Will Moore for a little bit more on corporate development.
Thanks, Brooks. I am going to talk about all areas of growth for the company but a little more focused on third part M&A. You know when we talk about it, we view at as three to four areas of growth whether that’s third party M&A drop downs, organic asset development and then organic commercial development. To give you the kind of an overview of where we are today, what we are seeing in the current environment and then how we plan and navigate through that environment. I don’t think it will come to as a surprise to anybody in the room here that there is an immense amount of capital out there looking for investment opportunity.
And some of the trends that you are seeing are new entrants in the midstream sector, whether that be infrastructure funds, newly formed MLPs, traditional private equity, or a hybrid of both strategic partners and private equity. What this has done it has made for a very competitive M&A process and you have seen multiples creep over time. Some of the recent large midstream acquisitions that have been announced have kind of exceeded sellers expectations on valuation, just based on low cost of capital and an abundant amount of capital that’s looking for a home. And so it’s a very -- you have to be very selective in your M&A process when we are looking at third party M&A.
Most of that third party M&A that’s being driven today is by private equity that is exiting existing investments. There was a real push here in 2012 with the known tax policy by private equity to try to get as many exits down in 2012 as possible. I think that’s been largely responsible for the uptick and deal flow. And that’s primarily where we have seen most of the deal flow today. Another area where we have seen deal flow is on distressed assets, that is strategic. Those deals tend to be pure in number and not trade as often given the valuations that the seller has in their historical valuation, and then the underlying value of the business as it exist today. We continue to look at those opportunities. Those opportunities are nice because they can be done on a negotiated basis most of the time and if there is a right fit and the assets are valued appropriately, we would participate in those kind of acquisition opportunities as well.
And then the third area where we see a lot of activity is your traditional E&P companies, as they look to access capital they are looking to divest assets and generally that’s gathering the processing assets, maybe some transportation asset. But they would rather take their return of the midstream assets and invest it in the drill head where they get higher rates of return. That’s still going to be an avenue for deal flow as we move to the future. You have seen some E&P companies have a captive MLP, midstream MLP that they are dropping assets into. I think that’s a trend they’d continue. I think you also see what we have seen with Marathon and EQT, where the idea of having a sponsored MLP-sub for a strategic -- you are going to see more of that which is going to also add to some of the competitive landscape that we are seeing our there for third party acquisitions.
So given that context in the overall M&A universe as it exists today, how are we going to navigate through it and how are we going to be successful in this highly competitive marketplace. So the first thing we do is we focus on opportunity origination both internally and externally. You know we don’t just sit around and wait for deals to hit our desk. We are out there turning rock, talking to people and trying to figure out where the investment opportunity lies. I think it’s important here to remember that most of our acquisitions on the midstream side have been privately sourced and negotiated. All the way back to Stagecoach in 2004-2005, that was a process that’s failed. We inserted ourselves in that and we were able to negotiate that transaction on a negotiated principle to principle basis.
Followed that up with our Bath acquisition which was sourced by a guy on Bill Gautreaux team, who let us know that that asset maybe trading and we were able to get in there outside of the process, negotiate that transaction. Moving on chronologically through it you look at ASC, that was a deal that once we got up into Pennsylvania, New York, we started looking at the other storage facilities that were available to buy. We cold called ASC and turning that into a negotiated transaction that also had the Thomas Corners development associated with it.
Similarly with US Salt. I called Mitchell here when he was on the other side of the table and was able to turn that into a negotiated transaction outside of a process. And then the last example here in the Northeast would be Seneca Lake. That’s once we acquired US Salt we became their landlord so to speak on the [caverns] and so as a natural extension to call them and see if they would be interested in exiting the business and we were able to negotiate that outside of a process.
And so that’s really where our focus is. We are going to look at the auction processes but we are going to be looking at other opportunities. We feel like private negotiated transactions lead to better valuations and better terms than some of the auctions that you see kind of as multiple [creep] that’s kind of been prevalent in the midstream space here of recent. You know as you have already heard John and Brooks talk about drop downs. We do see that as a vehicle for growth. We really like the businesses that are at NRGY today. We see those migrating down to NRGM over time and those are going to be valued based on what we think the long-term sustainable cash flow of those businesses are, and are going to be structured in a way that’s been official to both NRGY and NRGM.
As we continue to go through this process, we worked hand in hand with the operators on their particular business. This isn’t a top down corporate development strategy, it’s a bottom up strategy to a certain extent. These guys have their relationships, are out there in the field, see the opportunity. They are out there sourcing deals hand in hand with me as I go out there and look at larger scale investment opportunities. And I think what's important here is that we are targeting assets that have embedded organic growth in that once we get those assets into our portfolio we want to make sure that we remain diligent on where we invest that capital and growth projects.
You would hate to have a good acquisition turn into a bad platform because of cost overruns and issues that would bring up in the organic growth side. And so we remain focused on investing capital in those businesses even after we make the acquisition. And that kind of goes to the last point on staying discipline, knowing who you are, staying your fair way and executing on things where you can bring expertise to.
I am moving on to slide 21 here and I think this one covers the COLT acquisition, and I am going to let Bill Gautreaux talk more about COLT because it fits in his P&L responsibility. But I think COLT is a combination of all those things I just talked about, it’s a high quality midstream asset in a prolific shale play that’s immediately accretive, and I want to emphasize that because most of the midstream deals that trade lately aren’t immediately accretive, with long-term fee based cash flow from great customers. And it has the additional element of having built-in organic growth, which is something we look for in all of our acquisitions. As Brooke said, Stagecoach, ASC, US Salt, all those have had built-in organic growth that has allowed us to generate high returns from the initial investments.
COLT is a great example of us going out there finding an opportunity, came to us through a relationship. We were able to enter into an exclusive negotiation with the sellers and get it at a value that makes sense for both us and them. And by entering into this we get a new platform for growth up in the Bakken, which we believe to be the number one or number two shale-based in the United States. And you look at the level of activity up there and where the asset sits in the heart of that activity, coupled with the ability to grow and the customers that are already embedded in the business, it really is a great acquisition for us.
The business itself is very similar to what we do every day. We have existing rail terminals, existing storage terminals and we are moving product everyday for our customers for a fixed fee. That’s what we do at COLT and the customer relationships that we have, every single one of the customers at COLT we have relationships on the NGL side with, so it’s a real crossover between our NGL refinery services business and the COLT business. And so it was just a natural extension as both John and Brooks said, of our existing business and one that we are really excited about. We would be closing that one Friday and we have big plans for that asset. As you heard John say, we see significant growth, easily attainable growth and a strong connection between that asset and our Bakersfield assets as we continue to invest capital in both.
Moving on to slide 22. I think this is kind of recap of everything that I have covered thus far. Our existing core assets and expertise is a great platform for growth. You couple that with a strong balance sheet and how we transform the company and our access to capital, and I believe that we are structured for growth moving forward. You know we started with the storage business, up in the Northeast, we transformed that business into an integrated storage and transportation business. It was more and more the revenue coming from long-term transportation contracts. We then moved into NGL storage in the Northeast and have continued to grow that business. We plan to do the same thing in the Bakken where you have saw us tack on acquisition and opportunities around our Northeast assets overtime. I think you will see the same kind of development in the Bakken over time. It’s a great area to make midstream investments and we plan in investing additional capital up there beyond just the reach of the COLT facilities.
And once again as John and Brooks have both stated, we are set up for growth. We have an aligned management team, flexible capital structure, two currencies with which we can finance and grow the company with, and we are excited about the growth opportunities we see moving forward.
So I think what we are going to do is we are going to pause for just a few minutes and we are going to allow questions of John, Brooks, Will and anything in that section that you would like to ask these gentlemen. Yeah, we are going to give you a mic.
Okay. Great. And if the answer to this is, we will get to that later in the presentation, that’s fine. But, Will, you know from a top level you talked about the COLT acquisitions, you are going to get great opportunities, great plans. Can you talk a little bit about the thought process that went into going after that acquisition, going into a new basin, going into a somewhat new line of business? And put some color around some of these growth plans. Are you kind of hemmed it until you are close so you can talk about the new opportunities set that it brings to the partnership?
Well, I think you have heard John set out what we expect out of the business going forward. The existing contracts in hand ramp up to about $58 million of EBITDA on 2014. That’s all contracted in hand EBITDA. And then we have plans far beyond that, kind of exiting ’14 of $75 million. To the thought process, we as a management team when we look at opportunities for growth, we want to be in prolific shale basin where we can use our expertise on moving product from market. All the way from the well-head to the burner tip or from the well-head to the refinery, in the case of coal.
And when we looked at it, I think the most successful MLPs out there the ones that can offer a suite of services in both NGL, oil and natural gas. And for us, we were looking for the opportunity to add a crude platform to the business mix and this was the perfect fit in terms of both valuation and return, and then the assets and customer base are very similar if not the same as the businesses we are already in on the NGL side. Bill, you want to add anything there.
Quickly, we are looking at projects throughout these shales. I think the couple that hits for us here were a customer base that we are already dealing with in PADD 1 and PADD 5, namely refiners. And potential linkage between this asset and our existing Bakersfield asset. You know the combination of those things and the complementary nature of the logistics and the fact that it creates a new beachhead and a universe of growth that we think could also lead to NGLs, is very compelling.
John, can you talk a little bit more about expected distribution growth in NRGY and also in terms of drop downs. Sooner than later, when you would give a rough estimate of when the additional drops would take place?
You know I think, as you guys that’s a board process, but I would think that -- I think you should expect that sometime in 2013 from us. I think that’s fair. And when I say sooner rather than later, I think this is our strategy to do this and so I think we would be as expeditious as possible given the processes that we need to go through. Your question about NRGY distribution growth, I think there is more to come on that. If you just look at the business today in kind of the underlying leverage to growth from NRGY to NRGM, I think without deploying more capital it’s about 1.5 times on a percentage basis. So I think if you think about the example of COLT, I think we said that was -- what was it, like 9% accretive at NRGM and 13% -- in round numbers 13% accretive at NRGY.
So I think that’s kind of the relationship. Now that will change as we restructure, as we do the drop downs I think that we will have to do some thinking about how to structure NRGY as a security relative to how to optimize the value of that on a long-term basis. You know with the mix of the IDR cash flow and then ownership in the LP units in the underlying partnership. We have got some work to do there but I think that’s fair.
John, this has been discussed a few times as it relates to step-change in EBITDA as you outlined, from 58 million to 75 million and I just want to make sure that I understand this. In terms of getting there and the associated capital commitment, if you could just share a little bit of color on that. And more specifically what I am wondering is it going to be that EBITDA progression a bit more linear or do you think it’s going to be a bit lumpy?
Are you talking about the....
I am talking about Rangeland and COLT.
Just because it has been mentioned so many times in terms of fiscal ‘14s contribution and the net $75 million after that, so I am just trying to get a sense for why we should think about the progression.
I think the -- and you guys can maybe know better than me, but I think the way that we have described this is, we will ramp up over the course of 2013 and exit 2013 at a run rate of $58 million of EBITDA there. And so I think that’s -- I don’t know if that’s a lumpy ramp up or not, Mike, go ahead.
I think to answer your question, Darren, relative to moving from that 58 kind of run rate I think what you heard is us looking forward at, ultimately seeing even greater EBITDA. That 58 is largely contractual as we run through fiscal ’13. I think this team has already, even though we don’t own the asset, looking at the asset and looking at potential for capital deployment and it’s that first layer of what we think may be some low hanging fruit relative to growing this business.
I don’t think we have -- we are ready to identify exactly what that capital deployment. What I would say is you know the way we are looking at that we think it is again high return and attractive....
Yeah, I think I would call it very efficient. You should expect it that should be very efficient deployment of capital. I think we described this asset. The guys that built it had some foresight. It’s really built for growth. For example the ability to add another rail loop up there and to expand the capacity, you know cost effective.
On the $58 million that we have talked about, the initial investment of $425 million plus $19 million of CapEx to spend, that does produce $58 million. So it’s $444 million with $58 million.
You know the way we look at that is similar to other projects where we have acquired and then ultimately can invest high return organic expansion around that acquisition, and ultimately better that return for the asset.
You know I think, as we look at it, Darren, I think that asset is kind of a $58 million, call it a mid-7s kind of multiple. I think that we think this expansion would kind of bring that multiple down to pretty close to six, kind of a flat six all in round numbers.
If there are no further questions for this section, I think what we will do is keep this moving. I am going to invite Ron Happach up, our Senior VP of Gas Midstream Operations.
Good afternoon. We are on slide 23-24. I will start off by talking a little bit about our business strategy and add as a shale to market operating strategy. Really hadn’t changed, our business strategy hasn’t changed since day one. Since we first acquired Stagecoach. Although the shale wasn’t this prevalent when we first acquired Stagecoach.
We will continue to contract a 100% of storage capacity in Northeast just like we have been doing, under long-term contracts. And we are going to attempt to achieve the same thing at Tres. Protect and expand the strategic value of the critical gas infrastructure and further enhance the long-term profile of existing assets through low-cost, high-return storage and transportation expansion projects. And continue to diversify cash flows through NGL storage and expansion and logistics expertise. If you look where we were 7.5 years ago, we had 13 Bcf of storage at Stagecoach. We have no pipelines, we had no liquid storage.
Today we are almost 80 Bcf of gas storage. Got almost 200 miles of pipeline. We not only offer storage services but we also offer a significant amount of transportation storage. And we continue to look at those projects and those opportunities and working on several as we speak.
Slide 25, shows our footprint of both the natural gas storage and our transportation assets. As you can see, Tres is about 34 Bcf, Northeast storage in aggregate is about 41 Bcf. Northeast also includes transportation. Although we talk about and it’s 92% overall contracted, but when we talk about the 92%, 11% of that at Tres is our hub services which continues to be robust. Now we are capable of 100 Bcf in total but some of that we are looking at in liquid storage. We think there is great opportunity in that. So we can use our existing, our future cavern space and our future development for liquid or gas. We will see what the market wants.
Moving on to the natural gas market and most of you have seen these same charts to the right. There is increasing demand due to coal to gas switching. Industrial demand is increasing and there is many future LNG projects out there that we hope to participate in a few of those. The intrinsic further out on the curve remains low and you can see the trend, so that presents challenges for the shippers, particularly the marketers. The asset location, connectivity, customer mix is -- we have high quality customer mix, our connectivity is both great at Tres and in the Northeast.
Natural gas supply from the Marcellus and Utica in the Northeast is great, but there is constraint in the Northeast pipelines. But that also presents opportunities for storage. If you look at where the spreads are today, just on a cash basis and where we are at Stagecoach, Thomas Corners and Steuben in that area, the supply there is in the mid-$350 range. If you look at what it’s doing in the Northeast city markets, it’s over $6. So the constraint actually presents some opportunity for storage and transportation.
Moving on to slide 28. Here again we are emphasizing, this is all the supply that comes into our Northeast assets and we have high connectivity. We are connected to Dominion and Millennium, Tennessee gas pipeline and Transco. All which give us access to the market. The Northeast storage and transportation hub along with access to the multiple pipes, helps us get premium demand right now for our storage assets and again we have a high quality customer base. We also have -- the platform also consists of quality assets that are integrated with natural gas liquids that have buffer market.
Slide 29. The thing I would want you to take away here is -- again, I will continue to emphasize this but we are 100% contracted out for Northeast assets based on operational capacity. The reason for that is we are highly connected. We offer very flexible services that separate us from our competitors. We had no seasonality requirements, we have no cycling requirements. At our Stagecoach facility, we also have n ratchets. So it gives the customers high flexibility that can put gas in the winter even when there is low prices, they can also take gas out when they need it.
So right now we are going through a warm spell here in December in the Northeast. We are having injections at all those assets so there is no seasonality restrictions, it allows them to take advantage of the spreads and keep storage where they want it. The other thing I would emphasize here is, we are integrating Steuben into the Arlington assets. That will give us market base rates and when we look at the map, which is just few slides later, you are going to see where Thomas Corners and Steuben are connected. So we will operate them more as an integrated asset. It will give the Thomas Corners shippers access to Dominion, it will give the Steuben shippers access to Tennessee and Millennium, which should increase our hub services.
I am going to go through and talk about each of the assets individually. I will go through these fairly quickly. I think most of you have seen these slide presentations before. Stagecoach is located where the star is, the circular star is on the North-South lateral. We are 150 miles northeast in New York City. It’s closest storage facility to New York City. That helps create some opportunities. The LDC is in the Northeast, like that there is less pipeline to transport from. And again, Stagecoach with its flexible facilities is a real plus for the LDCs. When it’s [called] at the beginning of the year, they can pull on as hard. When it’s called at the end of the year, they can pull on hard, and they can also take advantage of the low gas prices. So again, no seasonality requirements.
We are 100% contracted. Again, we have connections to Millennium and TGP. And I would also add, we are connected to Transco through Marc I which started service December 1. Again, 18 horizontal wells, high performance, and high quality customers. And that ConEd, not listed but National Grid is another one of our customers as is New Jersey Natural, as pivotal part of AGL.
Thomas Corners facilities, slide 31. It’s located 40 miles west of Stagecoach, 5.7 Bcf. Again, it’s market based rates, contracted through 2015 and connections to TGP and Millennium. And even though we say indirectly to Dominion, in April 2013 we will also be connected to Dominion through Steuben. That connecting pipe is already in place. So we can do that today if we had to tear up from the service but that will all be available April 2013. Ten high angle vertical wells provide two-cycle service. And again, a high quality customer base including Corning, Merrill, Tenaska, and Iberdrola.
Steuben, designated by the S to the far left. Again located very close to Thomas Corners, approximately 40 miles from Stagecoach. 6.2 Bcf of working gas, it’s 100% contracted today and even though today it’s cost of service facility, April 1, 2013, it will be in a market base rate facility. 11 vertical wells. 60 of capability withdrawal, 30 of injection. Again, a high quality customer base with PSEG and Elizabethtown.
Seneca Lake, our newest storage facility. It’s a Salt owned facility rather than a depleted reservoir which separates it from the other facilities we have right now. Again, located in Schuyler County. It’s approximately 40 miles from Stagecoach West. Right now we only have 1.5 Bcf of working gas. We are looking at expanding that by another 0.5 Bcf here later in the year. It’s 145 capability withdrawal, 72.5 of injection. It’s 100% contracted with weighted average of 2016. Again, investment grade parties. It’s connected to Dominion and Millennium through approximately 20-mile line. And we acquired it in 2011.
Our next slide on page 34 is the Tres facility. It’s located approximately 100 miles southwest of Houston. Today it’s about 38.4 Bcf of working gas. It’s expandable to about 48 Bcf. It’s capable of 2.5 Bcf of withdrawal, 1 Bcf of injection. 83% contracted when you include about 11 Bcf of interruptible and firm parks. We continue to have robust activity for hub services. We are connected to ten intrastate and interstate pipelines. Strategically located in the supply basin the Eagle Ford. We are working with a number of customers with regard to power plants and also we have a project that we will be working on. It should be completed third quarter of next year. We call it the [Copeno] pipeline it’s also known as the Tres extender. It’s a 24-inch pipeline from the [Copeno] plant that will connect directly into the main hub of the Tres facility and present additional wheeling opportunities.
Our transportation asset overview on slide 35. Our North-South facilities. We have about 325,000 of firm capacity. We are looking at and been working on a Phase II project. We are connected to both TGP, Millennium, and I would also add in there in that now with the Marc I, we have the ability to get gas down to Transco. The Marc I we have just put in service here on December 1. It’s 450,000 of firm capacity with ten-year contracts. A 100,000 of that is expected to be contracted sometime in the future. The firm shippers had a ability to turn back capacity. They turn back a 100. Part of that was they wanted us to build a 30-inch line from start day one. So they committed for an extra 100 with the right to be able to turn back a certain amount of capacity. And they have done that. And I think it’s just the market evolving right now.
We eventually think in the future that we will have that contract in our firm contract, it’s not to be able to recover those costs and the interruptible transportation services. The East pipeline is what we call our Inergy East Pipeline. It’s a 37.5 miles 12-inch pipeline. It’s connected to Dominion which feeds our customer [NISEG] right now. We are looking at opportunities to connecting the north lateral from Stagecoach into the East Pipeline to present additional opportunities between Millennium and North pipeline, TGP and the Marc I.
The Commonwealth Project. It’s a proposed 120-mile 30-inch pipeline which we are working with UGI and Washington Gas Light. We have slowed down the activities just because of the market dynamics going on right now but we continue to market it and we think it’s a great project. If you look at the market dynamics right now, TGP is own four is filled up through that capacity. Transco Leidy right now is basically flowing that capacity, so there is an additional 1000 wells that are completely or currently shut-in. So we really feel like it’s just a matter of time before a project like this gets built, looking for a new market, looking for more liquidity.
Slide 37. And this emphasizes what we have already went through. We are 100% contracted at each of our storage facilities except for Tres. And we look at Tres it’s 83% contracted when you compare the hub services. Our transportation profile, 325 in the North-South, 550 on the Marc I, and our East pipeline of 30,000. Under long-term contracts with high quality shippers. The graph at the right is important. Over 50% of our customers are LDCs or utilities.
To sum it up, Inergy’s natural gas storage and transportation assets are strategically located. We have focused on opportunities complementary to our existing asset. And again if you look at where we were back in 2005 and where we have grown that footprint, we want to continue to do that and we will. The ability to capitalize on interruptible storage opportunities in Northeast in the Marc I, Tres has leveraged to improvements in gas storage and I would also indicate liquids storage fundamentals. We have got high return organic growth projects to move the partnership forward, further expand Inergy’s operations. And those include the Marc I which we just put in service, the Tres Palacios header which we also call the Copano project, it’s 20 mile 24-inch pipeline. The Seneca Lake storage expansion, we have up to 10 Bcf of expansion there. Tres storage expansion which we may use in both gas or liquids or both and further leverage the NGL assets and expertise with existing natural gas storage and transportation assets. And those include the Watkins Glen and also an additional NGL storage at Tres.
Thanks, Ron. I think we will pause and if there are questions for Ron and our natural gas storage and transportation business, we are happy to answer those right now.
Yeah, I was just wondering if you can put some color or discuss a little bit -- I will break it in two parts. I mean Tres is contract (inaudible) rollover sooner or later we know how to press that market in but I am just curious what your sense of the rollover market might be. Are you going to have to reposition the asset a little differently, waiting for a time to really firm up long-term contracts. And the in the Northeast even though we are talking about 15, 16,17 as the average life, I am just curious as what kind of demand is out there for the storage. And is there an opportunity to strike when the iron might be hot, much like people did in Mont Belvieu where you go to your current clients and get them to extend the contracts now, where there might not be space for them two years or three years from now.
All right. First let's take the Tres question. I feel like with Tres we are in the bottom of that trench right now as far as the economic conditions. It is a going to be a challenging market to renew those contracts but we feel like we can renew a majority of them at the existing rates, and if not we will cover those through hub services like we are doing today. Northeast assets, we are in talks right now with a number of the high quality shippers. If you look at what we did at Steuben when we put those assets in market-based rates, we went to those shippers and we are able to get five-year extensions on those contracts and we hope to do the same thing at Stagecoach.
The existing customers, particularly LDCs love the storage. They love the location. It’s highly reliable but they are also governed by the PUC. So it comes down to, we are in talks with them right now but most of those contracts don’t roll off to 2017-2018, so it’s a little early for them to commit.
Could you expand on the Tres Palacios as it relates to liquids market. What's the opportunity there for you and what kind of a capital may you need to invest?
I will expand on both of those and may be Will will jump in here too. But obviously we have got a number of -- Mont Belvieu is -- and I am more on the commercial -- on the commercial standpoint I am more on the natural gas side. But we can use the cavern number four as we call it, for liquid storage. We also have the right to some other caverns that we can use for liquid storage. We have had a number of entities come to us and are in discussions with those entities and companies right now. They are very interested in liquid storage. Either to short-term storage if the pipeline goes down or processing goes down. So there is plenty of opportunities here. I think you will see us in the near future announce some liquid projects in that area.
Yeah. I might to add to that. We have people right now that want to lease liquid storage at Tres. Okay. But what we are looking at is, where are the assets positioned. We are sitting right next to chemical demand and lots of chemical demand right around us. You have got new pipeline capacity running right through the facility with Y grade. You have got new processing plants coming out of Eagle Ford and you are 20-25 miles away from water in the Freeport area. So what we are trying to figure out is, we know we have a storage project there but we are interested in trying to decide what else is there and how we can we link that storage to something more than that. And so because of that it’s still relatively early stage. But we will be leasing storage there and we hope to be doing more than that.
I wish I could answer that. I mean the storage project alone will be accretive but it’s not going to be a big needle mover for the company. That’s part of why we are trying to do more. But I can't really give you guidance.
Ron, right now the gas is going north to Canada, Northeast, Southeast. Do you envision some of Pennsylvania gas going to Midwest?
I do. There is a number of projects out there. One in particular that’s from Ohio going over to the [Bector]. I think it’s [Bector] project. Yeah gas on gas competition right now.
Could you provide more clarity on the shipper that pulled off of more flow and I guess should we expect the pipeline to be shipped at 100%, just with the 18% at interruptible or is the new capacity 82%? So now capacity as far as utilization?
I think the question on the 100,000, the Marc I. The shippers -- first of all when you are first developing these projects that the shippers wanted us to build this pipeline larger than the 24-inch and so they came to us and said, what do we need to do to increase this to a 30-inch pipeline. We needed at least 550,000. They had a right under certain timing conditions to be able to de-contract. And they decontracted back to the 450. Now the customers, there’s four of them, and they all took an equal percentage for the contract, prorated down a 100,000. So one of them missed one of his but it was Anadarko, Chesapeake, Mitsui and Statoil, the four shippers. Does that answer your question?
And how the 100,000 as far as we are contracting, is that your other part?
We expect to build and sell that capacity at least initially on an interruptible basis. I think what you are seeing with the market right now is so much gas out there, we have got some warm weather right now. And the shippers kind of looking between the producers and LDCs are kind of looking and saying, what we want to do with the gas there is so much supply out there. But I expect in the future we will either be able to sell it, we will be able to sell some of that on a firm basis. I hope to sell it all. But be able to recover our cost between what we sell firm and what we sell interruptible, at or above where we would have had it.
I think your question -- are you asking us if you should expect less revenue on a going forward basis from Marc 1, yeah, as a component of our guidance?
Yeah, I think you should expect that we will -- the original economics of the deal, I think as Ron said, we will either sell it on a firm basis or make that corresponding revenue on an interruptible basis from an expectations point of view.
No. No, it was a onetime deal.
The 450 is in -- that’s in for ten years now and started up Saturday. So we got a 100 left to sell but the 450 is good for ten years.
There are no further questions. We might take a two minute pause, a break, give you a chance to stretch your legs. On the webcast, we will back, it looks like about 2:51 Eastern Time and we will restart the presentation. Okay. Welcome back. I appreciate everybody interested in sitting down quickly. So next on the agenda here, we have Mitchell Dascher. Mitchell is our President of US Salt. I am going to let Mitchell come up and talk about his business. Thank you.
Thank you, Mike. So we are starting on page 40. So what is a salt company doing inside an energy midstream company, now we will talk about that. We are located physically right inside the sort of sweet stop of Inergy’s Northeast storage platform. And in owning a salt assets as I learned from Will Moore in the Northeast, is very valuable as it pertains to storage. Because people have to develop storage in the Northeast other than the reefs that are kind of all used up. You need new salt and you have to have a way to get rid of the salt. And we get rid of the salt profitability with the existing facilities.
There has been a whole host of projects over the years, whether it be Dominion in Pennsylvania, (inaudible), that proposed natural gas storage, and it never got off the ground because they had no way to deal with the brine. We are certainly vertically integrated into the existing midstream platform, whether it be natural gas storage where we would have to take Ron’s brine as he developed the cavern or as we develop storage base for natural gas and with liquids brine needs to go, flow both ways, in and out to operate the facility. So we are very very tied in to the existing assets.
We have a long history of doing this. We started natural gas liquids storage in 1964 and we have hosted the natural gas storage facility since 1996. And we are certainly a sustained source of growth for -- every year we pump out basically a Bcf of space for natural gas and a little bit more than that in terms of millions of barrel for NGLs.
In terms of the business, we are very very stable. And we owe that a lot to our long-term customer base and it’s high grade. We get paid everyday for what we do. The one input in salt making, and we will talk a little bit later about some of the specifics of slat making, one that is a little variable is energy. And US Salt does a very good job of mitigating any type of energy spikes or anything with our dual fuel capabilities. And unlike some salt businesses we don’t have weather related exposure. Our type customers are bakeries, industrial customers etcetera, pharmaceutical customers. So if it snows, they buy from us, if it doesn’t snow, they still buy from us. So that makes a little bit different.
We talked about the storage expansion capability a little bit. Certainly the next one up is the NGL storage at Watkins Glen. It will be really a race to see whether Bill stores NGL first or Ron gets his extra half Bcf of natural gas. And there is a further added bonus if you wanted to expand the Bath facility, to store NGLs or natural gas where we brine every day. We can certainly take that very economically from them.
And the nice thing about having a salt facility that’s a 120 years old is there is always opportunities to improve it. And thanks to Inergy, we have been able to do a lot of that. But there is much more to do, improving packaging capabilities and efficiencies and also our evaporator system, upgrading that and enhancing that. So we are excited about the future.
So let's talk a little bit. We will dive deeper here into salt. We are going to talk about dry salt. Dry salt is the stuff you can hold in your hands. Dry salt really comes from two different places. Underground deposits which are bedded salt of salt domes like Tres Palacios. US Salt is in a bedded salt deposit. And then oceans and lake brines like the Great Salt Lake or the San Francisco Bay. Underground deposits are exploited in two different ways. One is with solution mining which is the process we use to make evaporated salt, where all you do is send water down a pipe and make saturated brine with it and boil it off. Or room and pillar mining, which is where you put men and equipment down 2000 feet deep, 1500 feet deep, to crush and screen and blast the rock salt out.
Evaporated salt is the purest salt, that’s want we make. Rock salt is the least pure and we will see on the next page, on page 42, some of the applications. Evaporated salt is at the top of the list here and you can see some of the applications for food processing and pharmaceuticals such as intravenous dialysis solutions. Versus rock salt which has a much more limited use base. More volume but much more limited use base. Primarily de-icing salt and a little bit of salt for (inaudible) use. And solar salt kind of bridges the two, it’s a product that isn’t really used in food and pharmaceutical but it is used in de-icing, it is used in a lot of water-conditioning salt and agriculture.
So drilling down a little further into the United States salt market. Evaporated salt, again the business we are in is the highest grade salt. It is used in the most diverse and highest margin applications. If you look at the graph in the upper right hand corner of the United States salt sales, overtime since 1990 you can see that all these markets, especially the green that we are located in, they have seen steady increases. Evaporated salt really hasn’t seen any steady increase in volume. It’s very very low growth business in terms of volume but it also doesn’t go down either, it’s very steady. And the pricing goes up 2% to 3% on average per year.
And you can see that pricing in the lower right hand corner that we are the green again and the big spike there in the middle to late 2000s is due to energy cost that the industry has done a good job of holding on to. In the lower left hand quadrant is some of the main uses for evaporated salt. Food again, very important. Distributors kind of masks a lot of the [work] conditioning. That’s going to be your grocery stores, that’s going to be your Wal-Marts, that’s going to be your Home Depots, it’s the way to get to the older customer who wants to buy a bag versus a truckload that we like to sell.
In terms of United States place in the world. China is the largest producer but industry is really regional. Transportation costs really drive, really are big contributor in the total delivery cost of the customer, which is what the customer what the industry basically competes upon. So I don’t think you have to worry about Chinese salt showing up in the U.S. The industry is very well consolidated. Three companies are approximately 75% of the volume, that’s K+S and their Morton Salt business, Cargill and Compass Minerals.
So drilling down a little further into U.S. salt operations. We are located just outside of Watkins Glen on the shores of Seneca Lake, right in the Finger Lakes region. And we again do provide this wonderful, sustained future capacity for energy storage. And the good news is we have got a long -- we have been there a long time and we plan on being there for even longer. We have got what I will call is much above our industry standard reserves. So I am very comfortable with saying we are going to be in business for quite a while. The business is very stable. Very recession resistant. John complements me every year as to who stable we are, which is nice. And the products we produce, again high quality food, pharmaceutical salt, chemical feedstock and water conditioning grade salt.
So how do we make this salt. As we mentioned, we sent water down through two separate brine wall galleries to become a saturated brine, 26% salt in the brine. Once above ground, the brine is sent via pipeline to the facility. Some of it gets further purification to remove minerals and it all eventually gets evaporated in this process here. That you can see off to the right. That’s a quadruple effect, evaporator train. Essentially what happens is we make steam in boilers. That steam then makes electricity. We are a power island, we make, co-generate all of our power. And then the low pressure steam coming out of the generators is used not once twice but four times in making salt. So it’s a very efficient decades old process, very well tested.
After the salt -- after the steam goes into the evaporators, the brine circulates around, gets heated up and salt crystals form, it becomes a salt slurry which then gets into driers where the remaining moisture is removed. And then it’s packaged in a variety of sizes from 26 ounce can that you buy in your home all the way you to a build railcar. And in terms of our boilers, we do have natural gas and biomass.
So what are the revenue drivers. Certainly volume is important. The facility runs at a very high rate of capacity and the volume and pricing, I’d say a very consistent predictable, we kind of mirror the industry trends. 35% of our volume is contracted and the rest of it we have to go out and work for every year but we do not have a lot of customer turnover. One of the nice advantages about US Salt being a small company is we are very close to the customers and able to solve problems very quickly. On the lower left hand corner you can see some of the salt we produce. Food grade salt, chemical feed stock salt. Pharmaceutical, water softening pellets, pool salt and brine.
So in terms of the growth for the US Salt, certainly we want to hold on to the customers we have. They are very important to us. But there remains efficiency and monetization opportunities to continue to lower cost at the facility. Continue to develop hydrocarbon storage, I think we learnt quite a bit of how to make salt wells that are good for hydrocarbon storage, not just salt since we have joined Inergy, and that’s been very helpful. And also with 25% of the industry still unconsolidated I think acquisitions would be of interest too. So thank you for your time.
Thanks, Mitchell. We will pause just for a minute if anybody has questions about the salt manufacturing business or the integration with our gas storage and NGL storage business.
I think you say in one of the slides, but I just want to be sure. The salt production part of the business is an MLP acceptable asset or is it just as a low percentage of the business?
No, it’s qualifying income.
I think there was a IRS letter ruling which we discovered before we made the acquisition.
Yeah, if you think about it’s just the production refining of a depletable natural resource. So it fits well within 7704 of the tax code, without any problem. It’s something we spent a lot of time on in 2008 before acquiring the asset. But if you look at the gamut of things that are MLP qualifying, this is one now versus then. This is one now that’s fits well within the definition and isn’t subject to private letter ruling. There are some private letter rulings that actually reinforce the MLP qualifying in each of those as well.
You know I actually think we could if it -- we are trying to grow our distributable cash flow if it had the characteristics that we like as an investment. One thing when we talk about this as a strategic investment relative to cost effectively creating gas and liquids storage development opportunity, that’s a bonus for us. But after having owned this business, 2008, this is some of the most stable cash flow that we have. Now all salt businesses are not created equally as Mitchell alluded to. You know this is a very good one but certainly, yeah, there was something that made sense. We got the management competency to run it, we would evaluate.
There are no further questions, I will ask Bill Gautreaux to come up and we will talk about the NGL and crude logistics business.
Good afternoon. So this is not a business that we have talked a lot about in the past because it used to be a smaller business and it was a smaller part of the company. But it’s got a great track record of sustainable earnings. It’s a rapidly growing business and it’s very well positioned for the significant growth in the crude and rich shales.
Ron described the gas business as shale to market, we talk about the NGL business as tailgate to burned tip. It’s basically the same thing, connecting supply with demand. We provide flow assurance to producers. We lower cost and lower risk for end-users. And the combination of those activities creates a synergy beyond the reach of our assets.
If you look in green shaded areas, that’s where our asset base is in both NGL and soon to be crude. That looks like a fairly diverse asset base but when you look at these shaded areas, I am not sure what color Vince used there, I am color blind, I guess tan. But you can see that our logistics and transport activity extends the reach greatly of these assets and creates a lot of critical mass for the platform. This Bakken acquisition that we hope to close on Friday will further build out the critical mass of the platform.
In a world our business strategy is growth. Rapid sustainable growth. Our objective is to grow our asset base organically and through acquisition when it meets our criteria. We intend to keep adding in similar areas to areas we currently own assets because we feel like we have a diverse portfolio of takeaway assets and we will continue to grow our producer services business and end use service business. Now the combination of these approach is assets and logistics consistently produces returns for us that’s greater than some of the parks. And so that’s a core part of our strategy.
I think a lot of you are familiar with this slide. It’s basically illustrating that the rich gas is the driver in the gas shales. We joke a lot internally about what superlatives we use but I am going to stick with the word that this is an epic expansion of NGL production and build out of infrastructure. We need more demand domestically and we will continue to need strong international support to continue to flow the projected rich shale NGL production. Looking at the broader market overview. There is a large redistribution of supply and demand taking place across North America. For the producers, flow assurance, just being able to flow your liquids and price discovery, making sure that you are able to monetize those liquids at premiums to dry gas values is paramount. And in a lot of areas it’s not readily discoverable. So that is a significant challenge for producers today and that is squarely in the middle of the strategy of our business which is really to kind of go as far as up as a well-head with a transport truck and provide flow assurance for those guys and get the product to market.
You know you are going to see an incredible build-out in infrastructure. A lot of this of course is driven by the crude, the gas spreads. Those remain healthy. They will continue to be volatile. We will need more demand and I think you are seeing a significant ramp up in demand both in the petrochemical industry on ethane and on the propane side with the PDH, propane dehydrogenation facilities. And then of course significant ramps in export capacity out of the U.S.
Most of the -- that means Bakken, Eagle Ford, Marcellus, Utica are the big NGL plays today. Most of the infrastructure the scalable infrastructure that’s being built is on Conway and Belvieu in Louisiana to some extent. Not a lot different than the crude side of the business where a lot of the infrastructure is moving to PADD II and PADD III. Exports, the capacity is projected to triple. I think there is even projects announced beyond a triple the amount of the current capacity. I think you are going to see a delineation in these plays between the plays that are approximate to this scalable infrastructure, storage fractionation, export, and the plays that are not approximate. And so the Eagle Ford being one of the more approximate plays close to the Gulf Coast but Marcellus, Utica, Bakken, those are really not approximate.
And so in those markets, you are going to see more local build out of infrastructure particularly Marcellus and Utica because you have got in PADD I which is really that whole East Coast and Northeast Coast market. You have got a demand curve up there that’s still much greater than supply and so today that’s supplied by imports out of the Gulf Coast and imports out of Canada and imports from overseas. But in the future you are going to see that resupplied by a lot of the shale gas production but to do that it’s going to take local fractionation, it’s going to take local storage, it’s going to take the reconfiguration of local pipelines, like you have seen with some logistics at Mariner West, Mariner East. There will be more of those and it’s going to take a lot of trucks and a lot of railcars.
A critical element of that will be NGL storage in those markets. A lot of the resupply -- a lot of the premium market supply has a seasonal curve both on propane and on butane refinery blending and if you want to participate in that premium market you have got a hold the molecule there.
Let's talk about our facilities and transport assets. The base of these assets is anchored by storage, fractionation and isomerization, terminalling, and trucking and railcars. It represents a diverse portfolio in the supply chain, a critical takeaway, the infrastructure you know right from the tailgate. If you look at our storage platform, we have got about 4.7 million barrels of local storage after the build out of Watkins Glen, which is 2.1 of that. Those assets are expandable to about 7.7 million of capacity. 83% of all NGL storage is in Texas and Louisiana. And when you look at the volume there, they are huge. That is our niche so when you look at the volume of LPG storage that we have, it’s important to look at it in the context of where it is.
Ours is in PADD I. PADD I has 10 million barrels of storage. At our current capacity we have 15% of that at our -- when Watkins Glen comes on we will have 30% of that. On the West Coast there is about 8 million barrels of storage and our current storage facilities on the west have about 7.5% market share. So this niche around Marcellus and Utica and then over on the West Coast and soon to be Bakken, that’s kind of our fairway and it’s local storage, it’s not the big hub volumes that you are seeing in the Gulf Coast. Very valuable, extremely high intrinsic value.
Moving on to the our West Coast facilities. This is an integral part of the merchant refinery services assets in California. It’s a sustainable fee-based business with upside from time to time. The assets there are very similar to the Rangeland assets. You know a very large truck load, unload facilities, large rail facilities, pipe interconnectivity storage. You know I will show you later on a grid slide but Bakersfield, this asset base I think is in a good position as a crude receipt point for California refineries. It also has great proximity to the Monterey shale, a part of the (inaudible) basin which could pay big dividends in years ahead.
Our transportation fleet. You know this is a critical wink in the emerging shales. Literally at the well-head with condensate and liquids that are coming off JT skids just right in the middle of nowhere, in rough terrain. How do you start flowing a well and get that stuff to market, that’s what this asset base does. We have actually gone out there, when we had retail we went out there with bobtails and picked some of the stuff up. This is also a business that’s a great example of when we talk about rapid growth, the kind of expansion we are seeing. In fiscal ’11, we held about 45,000 barrels a day and fiscal ’12 we held about 63,000 barrels a day. Our run rate for fiscal ’13 is 100,000 barrels a day, and that includes the integration of two assets that we made, one in ’11 and in ’12.
You know this business also helps position our entire supply and logistics effort because it’s kind of the first tool for positioning with the producers and it leads to other opportunities. But this business has grown, there is a clear leader in Marcellus, Utica at the current time.
Moving on to our supply and logistics business. This is the engine that drives flow through our asset base. The assets are critical to the logistics business getting its position and for its ability to execute with producers. And it’s rapidly growing, the producer and end user services business. That drives flow through our system, market intelligence and that’s how we get a lot of our development opportunities because you are on the ground, you are in the business, you are serving producers, you are serving end users and these producers see their flows increasing, it creates opportunity. And the more control that we have of that flow, the more opportunities we have to toll that through our assets and perhaps use it to underwrite future projects.
So again, what's the focus of that business? It provides flow assurance to producers and optimal net backs. Again, it pushed flow through our assets. It also has a robust hub supply and hedge service business with a diverse set of counterparties. That business is -- it’s very disciplined. Generates consistent profits and it actually protects the company from a commodity standpoint. We operate it with very low commodity risk to the point where volatility consistently is an expansion to our margins. You know when you see market dislocations and you see day to day price volatility, we are generally making more money based on our profile and again it’s kind of this logistics activity, this hub liquidity that we are providing for diverse counterparties combined with transport storage.
You know it’s another example of when I talk about rapid growth. This business in the prior fiscal year marketed 118,000 barrels a day of NGLs. When we look at the ramp up on some of our producer services contracts and where they are going to be, not so much in the 2013 but in 2014, we have got visibility to see in that marketing volume growth to approximately 150,000 barrels a day, kind of just based on the visibility we have today. And if you look at the right I mean we have got hundreds of relationships in this industry but certainly we wanted to illustrate some of the key relationships we have with producers, namely refiners and gas processers in Marcellus-Utica. This is a key link in our thinking on Rangeland as we have mentioned before because we are already very involved with both East Coast and West Coast refiners.
Moving on the Rangeland COLT asset. We are extremely excited about this acquisition, it’s immediately accretive, it’s got low hanging growth opportunities and it’s highly complementary to our strategy. Really dramatically expands our universe of development opportunities. It’s another example of parts of this platform feeding the others. So I mean I think in this area you will see a standard of a basin based on crude assets but likely very well have that generate NGL opportunities for us.
Couple of highlights on the asset base itself. This asset base, it’s 90% contracted to day, we think it will be 100% contracted very quickly. I mean the negotiations are underway, it’s almost close enough to say that it is, but I am not going to say that it is. It’s all take or pay contracts. The crude and the NGL logistics business are highly compatible. We think they will be synergistic because it’s going to, I think this asset base is going to feed opportunity to our Bakersfield asset base which has been primarily NGL and I think you will also see it feed us NGL opportunities around the asset base itself. It’s going to be a great growth platform. It’s going to diversify our earnings base and we think this Rangeland network will be a point of liquidity for this part of the Bakken.
Taking a quick look here. So you see the COLT terminal right here in Williams County. The COLT connector, it’s a 10-inch 21-mile pipeline. It’s got up to 75,000 barrels a day of capacity. Going to Dry Fork. Just want you to note that this is one of the most connected asset bases that’s also a rail terminal in that region. And so at COLT we will be able to load 120,000 barrels a day of unit trains. There are two pipe interconnects. One to Banner, where Banner gathers into that facility. We also have the rights to go out of that facility into Banner. And then we have an agreement right now with Bear Tracker for another connection that will come in right around the COLT area.
Then when you move over here to Dry Fork, the Beaver Lodge area, that’s an intersection where there are four additional crude pipelines, Enbridge, Tesoro, Hess. And we are connected to Tesoro and Enbridge at this point. Banner also connects there and we have discussion underway with Hess. And so I think it’s important to think about this asset base as not just a gathering facility that loads unit trains but this is meant to be a point of liquidity. We will be able to take crude in by truck, crude in by pipe, store crude and segregate it well. And then we can take crude out of there by unit train and we can take crude out of there by pipe or by manifest train.
I think you guys probably know a lot of that North Dakota these days. But just quickly, North Dakota has emerged as the number two producing state in the country. It’s producing light, sweet crude. These assets are right in the heart of the three most prolific counties, which are right here. So Williams County, Mountrail County, McKenzie County. Plus or minus 68% of all the production coming out of Bakken right now. It’s within a 50-mile radius of this facility. When you look over to the right, we have what we are calling a base case production forecast here but we are really not crude production forecasters, but what we have done is taken like a [bentech] low case which I think is 2.1 million barrels and Turner, Mason low case which is very conservative at 1.1 million barrels and kind of said, our slag and with other people that we have debated with, it’s somewhere around 1.5 million to 1.6 million barrels a day by 2020.
That’s sort of the curve in production that we modeled when we were evaluating the acquisition. We don’t really have direct exposure to that curve because we have got fixed volume take or pay contracts but certainly we want to see robust growth to harvest what we think are the additional opportunities around the facility.
I won't spend a lot of time on this but the North American crude grid. A couple of points that I want to make here. You will see here again a lot of the infrastructure here is around PADD II and PADD III. You know PADD III being the mega refining complex for the U.S. When you look at an NGL grid, it’s not to dissimilar, I mean Conway and Belvieu, right around here and right around here. Big constraint that you guys all know about here at Cushing. That is looking to get some relief with some of the expansion projects. Keystone coming on to PADD III, the Seaway expansion, the Longview pipeline coming out of Permian. And so you will see more flow coming out of Cushing and into PADD III, which will decongest Cushing to some extent.
At this point another key element that we are focused on is you just don’t really see any pipeline infrastructure to PADD I and PADD V refiners. There is more than 2 million barrels of light sweet demand between those two markets and the alternative is all Brent based imports of crude. And so we think this is kind of the driver of what we think is a very sustainable long-term movement of railcar out of the Bakken and other emerging light sweet shales to the west and to the East Coast.
Adding to that, we will keep talking about that dynamic. We can't predict what the price of crude is going to be or what all the spreads are going to be. We did not predicate our thinking on this asset around that. A couple of things that we feel pretty good about. This new capacity that I just talked about going into PADD III. PADD III over the last couple of years is noted for being that market that actually reduced its ability to take light sweet by almost 0.5 million barrels a day and spent billions of dollars retrofitting to take heavy crudes and equivalent of amount of 450 to 500 a day.
And so they can continue to take more light sweet but they will be saturated quickly. And they are still waiting on heavy crude to come from Keystone out of Canada. Again, between the East Coast and West Coast there is about 2 million barrels a day of light sweet demand. I don’t know, the breakup is somewhere around 800,000 a day on the East Coast, about 450,000 a day in the Pacific Northwest, and about another 800,000 in California. What you are seeing is major receipt facility buildout in the East Coast. I mean literally you are seeing refiners that were going to shut down that are now robustly back operating. And I would tell you probably the main reason is that they have figured out how to get unit trades of light sweet crude and the economics are hugely compelling.
If you look at some these historical spreads, year-to-date 2012, I don’t how current is this -- so this is a little old, it’s through September. You know the advantage to the Northeast was almost $13. Up here around Seattle it was almost $16. Southern California, $13.5. Now we don’t see those numbers as sustainable at all. They may turn out to stay out there but we are certainly not expecting that they will. What we are focused on really is if you look at the load capacity of our facility, a 120,000 barrels a day as it stands. Every dollar move in the crude at that volume is worth about $45 million to our refinery customers. So when you are seeing spreads like this of $10, that means the four guys that are contracting this service with us between them are clicking off $450 million of feedstock cost savings. And so $45 million for every $1 at our 120,000 barrel a day capacity, that is what is compelling and just the yield of this specification of crude alone, we think that some of those refiners is worth $3 to $4, notwithstanding the discount that Bakken has to create to ensure that this crude is able to flow and flow to those refiners.
That’s the premise for us. And I think you will continue to see this, the major receipt facility buildout. I mean right now on the East Coast there are either built or announced somewhere around 700,000 barrels a day of capacity. You know you have seen ramp ups in the Pacific Northwest. California is going to be slower to the punch. Part of that is the nature of their crude feedstock slate. They crack a lot of heavier crudes from offshore California. The A&S that they bring down is also heavier than the Bakken light sweet. But they do have a significant light sweet first component but it will be more complicated for them to configure their slate. They also have the issue of gaining California and trying to figure out how to get receipt facilities permitted and whether or not they actually have the space at their existing facilities. It’s a challenge.
So again that’s why we think our Bakersfield asset -- I am going backwards here for a minute. You look there at the where our asset is here in Bakersfield and you will see that there is a little pipeline network there. So that’s why I kind of call Bakersfield the gateway to the California refiners. If we can get a receipt facility in there we think that we maybe one of the first ones to provide access to California.
So in the end here on this slide. We don’t know exactly what the spreads are going to do but our belief is that PADD III will saturate and that if you are a Bakken or other emerging shale light sweet producer, you are going to have to price your crude to flow if you want to get it into these other light sweet markets, which are going to basically be PADD I, PADD V. And mostly the way to get there is rail.
You have heard about a lot of crude unit train load capacity being built or being announced. You know there is, I think there is somewhere in the neighborhood of probably 800,000 barrels a day. They are not all the same type of facilities. We certainly think -- of everything we have seen, we think that the Rangeland assets are about as good as it gets in that play. It’s a high performance facility, and it’s a first facility to meet the Class I 120 unit train standards of BNSF. It was built by pipeline people that came out of Sunoco Logistics. The same guys that were involved in the Nederland Terminal. They understand what you needed to have high quality stable assets that are high performance and that are scalable. And so this asset was built with that in mind.
It’s been operated as an open access facility which maybe there would be ways to make more money otherwise but what that has done for the refiner customer is given those guys an opportunity to go gather their own crude, Tesoro being one of the bigger buyers in Bakken. Take it through our facility, put it on their cars, bring it to their receipt facility and control that sensitivity that I talked to you about, $45 million for every dollar per barrel of crude when you are using a 120,000 barrels a day. So if you go look at Tesoro’s earnings releases and they will give some sensitivities on how they have cut cost.
So again this asset was built with quality in mind by guys that know how to build those types of assets. Couple of other things we do there. We have got 600,000 barrels of crude storage at COLT and another 120,000 at Dry Fork. We segregate those for the customers because these guys are often times gathering this crude and taking a ride into their refinery so that they are particular about what their standards are. Some of them may even want to combine a couple of types of crudes in that segregated storage. So they have a lot of flexibility to do that even to the point of having truck receipt facilities, racks assigned to them. I would also say that this facility is differentiated by the level of connectivity that it has. I don’t know of any other unit train facility that has the pipeline connectivity that we will end up having as our connection agreements or realized.
So those are all things that when we did diligence on this, we are seeing how is this facility different than others, what's the advantage? We came up with a number of them. And I think that’s why we have approaching 100% contract level, all take or pay contracts. Four year in duration and I can tell you this asset has been marketed on a scarcity basis that what we have got, we have got people that want to be in that asset that are not there right now because they weren’t able to move quickly enough and that will be kind of the basis for our expansion.
Just a quick visual here. All we are trying to show you there is that there is over 300 acres at this facility. It is very expandable. You could probably fit another 15 tanks in this tank farm. We have got two rail loops. The second, right here is our rail loading arm which is covered. Somebody asked me about that at lunch. That’s very important, in January in North Dakota. And this is access to the second loop. That’s likely where we would look at on expansion opportunity. You know truck racks, pipeline connectivity etcetera. Lots of expansion capability.
Okay. So the overall platform. This is an integrated platform. The various disciplines drive opportunity in the other disciplines. You know it’s assets plus expertise. It’s got a great track record of earnings. Very disciplined approach to commodity risk management. Very low commodity risk. Volatility is positive to our earnings. And I think if you go down here and look at the relative contribution you can see that this platform is becoming very well diversified. It’s going to have a big piece of crude of NGL facilities and then a supply and logistics component and we expect growth in all three of those segments.
When you look at the opportunities, the bottom part of that page, transportation, producer services, fractionation, the G&P business, just like the way that we came upon the Rangeland opportunity, I mean those are things we are evaluating everyday in multiple plays. And looking at where do we have assets, where do we have logistics activity. How many points is this opportunity hitting on? So I would tell you that we will accomplish something in that arena but I am less certain of the timing. When I go up to the top here, these are really the opportunities that we think are immediate and are low hanging growth. Obviously, the Watkins Glen facility, you know the market is just waiting for that to come up. As soon as we have our permit, we will be four to five months away from being in service and that is going to be a great facility for Marcellus-Utica resupply of PADD I.
The new COLT hub that we hope to close at the end of this week, we see immediate expansion opportunity to expand our loading capacity, expand our storage and ideally we would like to link that to a Bakersfield receipt facility. So we would want to target refiner customers that could help us facilitate all of that with the expansion because then we would get an expansion at COLT but we would also get an expansion at Bakersfield. But we will evaluate that against the timing of -- we think we can contract an expansion at COLT pretty quickly. The question is, can we contract it with people that would want us to built a receipt facility in Bakersfield. That may take longer and so we will have to make a decision on relative return versus timing.
In summary here I think the combination of our logistics expertise and our strategically positioned assets in these niche markets against a backdrop of the prolific shale production, is going to continue to produce sustainable results for us with significant opportunities for growth. Again facilities and transport plus supply and logistics expertise is really what's creating our tailgate to burner tip service offering and when it comes to earnings, we are producing earnings as a result that are greater than some of the parts. So thank you.
Thanks, Bill. If anyone has questions for Bill, we will take those at this time.
Just a real quick one. Could you remind me, you don’t own or control any of the rolling stocks, is that correct? You are just loading it up, right?
No, we own over 400 pressure trailers -- I am sorry, did I say or 400 or 500.
I think he is talking about the Rangeland. Is that...?
Yeah, I was talking about the crude.
No. I mean Rangeland, the only thing that we will own when we close this acquisition are origination facilities. So basically you know receipt facilities to unload or taken by pipe, facilities to load unit trains, storage, the pipeline interconnect that bidirectional. And then another terminal that’s situated around multiple pipeline interconnects.
Okay. So therefore we could take or pay if your customer has issues with the rolling stock, it gets delayed. Not your loss, we still get the money, correct?
Yeah. You know the customer is required to put the volume through. We are required to be able to receive it and make the facilities available. Now we are going to be working arm in arm with these guys. We want them to be happy and that’s what's going to add to further gathering opportunities. But it is their responsibility.
Could you talk about your asset footprint in Bakersfield? What kind of acreage you have? What's the rail connection, etcetera, etcetera? And your permitting challenges?
Yeah. Well, connections to the BN and to the -- I don’t know the exact acreage of that facility overall but I know that we have a lot of surplus acreage. The permitting environment is nothing like what you see around the LA basin or San Francisco and California refineries. So we have been through some major construction there over the last three of four years and permitting, it’s taken its time but it hasn’t been an impediment. And we see that as being a big advantage for us as well as right of ways that we own around that area. And but the rail link there is not just permitting but the fact that we are short drop from pipeline connectivity into those refiners. And we could rail to them as well.
Yeah, I think there has been talk of another facility out there on that one. It’s pipeline connections just heading south. We have the ability to existing pipeline that’s in the ground to go both north and south on the crude pipelines that are in the California which is a real advantage of our facility.
Could you talk about whether, in your due diligence or specific discussions with your refiner customers. I mean I think the cost numbers that people throw out are somewhere between $10 to $15 to rail some of those through to different coasts. You know a case is $13 bucks are plus or minus right now which are historically very high. You have got four year contracts which are good but they are not ten-year contracts. I mean how do we know this market exist in any form like it is today, you know five, six, seven years from now? And what discussions have you had with refiners that they are 100% or whatever committed to continuing to be a customer long-term not medium-term.
That’s a good question. I am trying to think of which parts to take first. Okay. So I think we modeled about $10 to the Pacific Northwest as our rail rate. I think if you look at Tesoro’s earnings report, they talk about something less than that, $8.5. East Coast rates are a little bit higher. In terms of sustainability I think it goes back to the same premise that you have got compelling returns on crude that wants to be produced at least at these crude values. Very soon about the only place to go with light sweet is going to be PADD I, PADD V today because there is significant price advantage. The refiners are actually competing for it. And you are seeing robust build out of receipt facilities on the East Coast because this lower feedstock is kind of lifeblood of the survival of those East Coast refineries. I mean you had two that were shutting down and now are coming back hard and you have got one getting ready to go through an IPO process.
I think when the -- so those customers, that’s one of the advantages I think to this facility is that it’s contracts are generated by refiner pool. We are not just going out there trying to originate. I mean these guys are using this lower their feedstocks cost and increase their earnings and they are doing that and it’s having significant impact. And we have a lot of conversations where the outlook is way beyond three or four years but they are not going to sign up for ten unless they have to or if it’s real compelling. And so that’s our premise.
Yeah, I would add some customer specific references there. The day before we signed this deal we had a customer come in, extend their existing deal two years and double the volume. We also with Tesoro, who is our largest customer, they dropped down their core days refining, their unloading facilities to TLLP for a ten-year take or pay contract with a minimum volume of 50,000 barrels a day. And then also the discussions we are having with current customers, those are all five to seven-year deals. Everybody is looking to take these out longer. And then I think if you look at the dynamics up there, people are getting more and more comfortable with the fact that going to Cushing isn’t tend end all be all for Bakken crude. And I think one of [Bakken Express] I think reiterates that the market is starting to understand that the long term home for Bakken crude is PADD I and PADD V.
There are no further questions. Does anyone need a break or we are wrapping up here. I will make this somewhat quick. The numbers. So I am on slide 68 for those of you on the webcast. I have to throw in the discipline around Bill’s rapid aggressive growth comments. So again I think we are committed to executing our growth strategy in a disciplined manner. It really starts with using a balanced debt and equity approach to our funding. We as a management team and I think we have operated this way historically, target investment grade credit metrics and I think when you look at that at NRGM it really stars with our focus on maintaining long-term debt to EBITDA ratio of about 3 to 3.5 times.
There will be periods briefly where you might find us above or below this as we execute on growth or finance our growth with equity. But I think over the long-term that’s where you should expect us to operate ourselves at NRGY. Again I think we have said that we expect to fund most of our growth at NRGM level and for NRGY we would expect to operate ourselves a less than three times long-term debt to EBITDA ratio.
In unique situations, I would say, and I think we had talked about this earlier, we would definitely look in unique or strategic situations to utilize NRGY or have them step in. And I think they have the financial strength to do so an otherwise really facilitate growth at NRGY Midstream.
Coming down the list here we will take a conservative approach to risk management. Again it is very simple. Bill alluded to this in his business. We don’t speculate on commodity prices and take speculative positions. We have minimal direct commodity price exposure in our business and just in every dollar of capital that we invest is extremely important. Looking for the returns commensurate with the project or the acquisition activity in the business that they are involved in. Our corporate family ratings last week. S&P and Moody’s rated NRGY Midstream, we are at BB flat at S&P, Ba3 at Moody’s. Both were stable outlooks. And when you look at our long-term distribution coverage, we would expect at NRGM, really supported by the fee-based nature of those cash flows to execute long-term distribution growth in about the 1.05 to 1.1 times areas.
And when we look you NRGY, I think we have said this in the past, we would look to flow the distributions that come up from NRGM to NRGY and pass those through to unit holders that have been covered downstairs at NRGM. And then we would tack coverage on our operating business while they set up at NRGY and I think John has alluded to the fact that we expect those businesses to migrate to NRGM in the near term here.
Moving forward, I just want to cover -- I know John has covered this, just to reiterate. I think it really kind of dovetails in with the transition that we had. Again, a little over a year ago we laid out some objectives. Those objectives when you look at the NRGM IPO, the tender offers around that IPO, the sale of the propane reduction of debt that we have had there. We have again delivered on those objectives of lowering our future cost to capital, strengthening our balance sheet and opening up really new growth opportunities which I think you -- with the Rangeland COLT acquisition starting to become more visible to your than it were otherwise a year ago.
Moving on to slide 70. Again this is really again meeting those objectives from a cash flow perspective. If you look back to 2012, consolidated adjusted EBITDA was derived about 43% from retail propane. I think that was actually depressed with the unusually warm weather we had last year and about 57% from midstream. You roll forward and you look out 12 months for us and to our 2013 exit run rate of adjusted EBITDA, including NRGY operating businesses as well as NRGMs, we see ourselves again 100% derived from midstream cash flow. About 56% of that being derived from our storage and pipeline transportation business, both gas and NGLs.
You have got about 37% kind of driven by our NGL crude supply and logistics business including the Rangeland COLT acquisition and about 7% roughly from US Salt. Moving forward, that’s a view of the financial, the cash flow implications. But in addition, I think an important point for us is the balance sheet flexibility and the strength that those transactions really added to the capital structure. We sit here with two strong balance sheets, NRGM levered on a pro forma basis at around 3.5 times. NRGY on a standalone basis levered at somewhere around 2 times. We have got two equity currencies again to utilize, to fund our growth and pursue our strategic objectives and I think we are well positioned at NRGY to facilitate that growth again as a supportive GP that can take back equity to help finance the drop downs or -- excuse me, in considerations for drop downs as well as to help finance third party M&A opportunities.
And then just to reiterate on John’s point, management owns about 20% of the NRGY units outstanding and when you look at the ownership in M, I think there is a strong alignment of interest as we look to execute and benefit both partnerships. Kind of moving forward here to slide 72. I won't dwell on this. This is a look at our historical financial performance and what we have done is pulled out the retail propane operations. Notably off this page, I think in the gross profit area, about 70% of our fiscal 2012 gross profit is derived from fee-based cash flow activities. When we pro forma in the Rangeland COLT acquisition, you pro forma in the Marc I hub line that we have just bought up as well as the Finger Lakes NGL storage business, that’s again, we have reiterated this but that’s about 78% of gross profit really derived from fee-based cash flows.
In the bottom graph, just looking at the growth in adjusted EBITDA. Over the last three years we have really been able to growth the adjusted EBITDA both at M as well as the businesses that set up at Y. And really that’s driven by organic expansion projects, our NGL operations and the underlying strength in those, as well as through acquisitions.
Just quickly a look at NRGM’s balance sheet capitalization. We have had a very busy couple of weeks. Last Friday we priced a new $500 million 8-year note, non-called for, senior unsecured notes offering. They are priced at 6%. We were on the road raising the permanent debt financing for the COLT acquisition. We will close on this notes offering I think on Friday. And expect to use the proceeds from that offering to fund a portion of the COLT acquisition as well as retire borrowings outstanding under our credit facility.
In addition to the long-term debt financing, I think importantly, probably most importantly relative to the financing activities at NRGM. When we signed up the COLT acquisition, we also signed a $225 million private equity placement for the COLT acquisition and effectively prefunded the equity portion of that purchase price. Really I think the gold standard of M&A activity and signing up the equity component of the purchase price upfront. Really removing any kind of equity overhand and otherwise pressure on our units especially given the liquidity right now with NRGM.
So on a pro forma basis from a leverage perspective, again I mentioned the 3.5, we are taking this $632 million of debt outstanding, you can see the impact of the $225 million of equity. Looking at our $180 million of adjusted EBITDA guidance that I will speak to here in a minute, that we have announced already with the COLT acquisition. It puts our pro forma leverage in and around to 3.5 time range at NRGM. So at NRGY, just a quick look at NRGY’s capitalization. Excluding NRGM’s debt, these two businesses, NRGY and NRGM standalone on a debt capital structure basis when we look at our credit facilities as well as the bonds outstanding downstairs.
What we have done here is presented September 30, 2011 and September 30, 2012 just for comparison purposes. And again this is just another iteration of the significant transformation that’s apparent with NRGY on a standalone basis, really having total debt to down nearly $1.5 billion to around $327 million at 9/30 of 2012. And total NRGY standalone leverage than when you take that in accordance with our credit facility, we take the operating businesses that sit at NRGY as well as the distributions that flow up from NRGM to calculate our leverage in right at around two times.
So I am going to spend a few minutes on the guidance slides. We issued press releases this morning with our 2013 guidance. At M it should be no surprise. On November 5 when we announced the COLT acquisition, we guided NRGM’s adjusted EBITDA to be in the area of $180 million for fiscal ’13. Just to reiterate, that includes the contribution from the Marc I pipeline project that we placed in service on Saturday. It includes the Watkins Glen NGL storage facility that we expect to place into service in the spring of 2013 and the contribution from the COLT acquisition.
Embedded in that $180 million of adjusted EBITDA guidance for the business is about $213 million of total gross profit at NRGM and about $33 million of cash OpEx. With the gross profit really being derived almost 90% from the storage and transportation segment of our business and the remainder from our US Salt segment, that is inclusive of the Rangeland activities. As we look forward on November 5 we also talked about the ramp of cash flow that we expect from COLT. And when we look forward as we exit 2013, we would expect the exit rate of adjusted EBITDA to, assuming no further acquisitions, assuming no further -- no drop down activity or additional organic expansion which I hope you all takeaway, we are not sitting still here, we are going to be very focused on more expansion definitely around our COLT hub.
We see that adjusted EBITDA from kind of the legacy businesses and COLT as we see it today, at around $215 million, again including the $58 million from COLT. As we look forward to that 215, we see that really being derived about 64% from storage and transportation operations. The $58 million from COLT would represent about 27% and about 9% from US Salt.
So just quickly, you can see the adjusted EBITDA out of income reconciliation. I am not going to dwell on that. You can see the depreciation, the interest expense and the lack of taxes to give us about $49 million of net income expected for 2013. And we also are providing growth and maintenance capital expenditure expectations for 2013 in the range of $84 million to $106 million for Inergy Midstream. Just quickly from the numbers on this page, working down from the $180 million of adjusted EBITDA for ’13, you subtract cash interest of about $30 million, you subtract out the midpoint of our maintenance CapEx and we are expecting to produce about $145 million of DCF for 2013.
Moving forward to NRGY. NRGY guidance that we put out this morning is consolidated guidance and should follow the way report the financial statements. So for fiscal 2013, inclusive of the $180 downstairs at NRGM, we expect adjusted EBITDA to be in the area of $260 million therefore NRGY standalone businesses really generating about $80 million of adjusted EBITDA. If you look at the $260 million, included in that is approximately $359 million of consolidated total gross profit and about $99 million of consolidated cash operating expenses.
Working -- again I don’t dwell on these but working down from adjusted EBITDA at NRGY we expect to produce about $28 million of net income for fiscal 2013. And then just quickly from the way I think we look at DCF at NRGY, you take the $80 million of adjusted EBITDA for the standalone businesses and working down to distributable cash flow, we would subtract about $13 million of cash interest expense. If you look at the standalone maintenance CapEx of that business at the midpoint, about $5 million. $1 million in taxes and then add to that at the $1.54 that we are paying from M currently in the ownership of units at NRGY, we would add back to that about $93 million of cash distributions inclusive of M and small amount of SPH distributions for about $154 million of DCF.
So with that I am going to stop and John do you have any closing remarks that you would like to make.
I think we have been over these points. I would just like to thank you very much for hanging in there with us today. Thanks for being here. We appreciate the opportunity to be in front of you and we look forward to executing this strategy on your behalf and on behalf of the people you all represent as investors. And with that I guess we will -- some last Q&A.
Yeah, we are going to open it up for Q&A. This is Q&A really for any members of the management team, any of our businesses.
Hi, Mike. You gave us an end of the 2013 run rate for NRGM for adjusted EBITDA but you didn’t give us any end of 2013 run rate for NRGY. I am wondering if you can help us reconcile that with adjusted EBITDA and even more importantly what you expect the DCF to be as part of this run rate after 2013 at the Y level?
You know I think at NRGY, I think when we look at the businesses that are setting up there, it’s primarily our NGL supply and logistics business. We are, as Bill pointed out, I think aggressively growing that business. I think when I lay out the run rates for NRGM I am really bridging kind of the contractual or the timing differences for what we have at NRGM currently. So you know those businesses we expect to grow. I don’t necessarily think there are any timing issues or bridging relative to NRGY. At a minimum I think when you look forward, both of these businesses, both M as well as Y should be performing in the $295 million or more rang of adjusted EBITDA depending on who successful we are in growing the business in 2013.
But that’s without any -- that’s consistent with your assumption, that’s without any further third party acquisitions.
That’s right. That’s just the project coming into place and timing bridges to 2013’s exit run rate. There is no further acquisition on the consolidated basis drop downs wouldn’t impact that.
So I guess isn’t earlier comment that John about 6% to 10% growth at NRGM and expectation that it’s about 1.5 times multiplier for NRGY. I guess we could use that for the end of 2013. I wonder if you can give us some elaboration on as NRGM continues to grow, expand and invest, the IDR at NRGY should accelerate pretty dramatically. Should we expect that 1.5 multiplier also to expand.
Well, I think that 1.5 multiplier is effectively assuming no further capital is deployed in the M and obviously as we grow our business we fully expect to deploy capital. But that isn’t the equity capital down at NRGY Midstream. And I think as you do that, that multiplier expands relative to your leverage.
Yeah, I would say that’s right, Doug. Certainly it expands simply by deploying more capital at M. I think the 1.5 was kind of the simple math ex increase at Y, M increase at Y. But the other thing that we need to give some thought too when we execute these drop downs and we think about how to optimize the value of NRGY, we are going to have to give some thought to how we engineer the of mix of IDR cash flow and underlying ownership of NRGM, to make sure that the market is efficiently valuing that security. So there could be some other changes subsequent to the drop down that’s really geared towards optimizing kind of the structure of NRGY for the investor. If that makes sense.
There is follow up for what you just said. Talk about maybe the multiple choice of what NRGY optimization opportunities there might be in the scenario you discussed.
Well this is just, how do you, multiple choice....?
I don’t know what the future holds and he don’t either. So why don’t we just talk to....
Okay. An example, I think we all know that the subsequent to the drop downs, we will be taking a -- if we were to drop down we would take a lot of units up at NRGY, perhaps pay the debt, all or some of it down. We would be then -- NRGY would be kind of inefficiently structured and that it would have its IDR ownership in a massive amount of units. So one of the things we could think about is distributing some of the M units to the NRGY shareholder to engineer that kind of mix of IDR cash flow and LP cash flow that the NRGY unit holder receives. So again, we are in the early stages of this. We haven’t gotten to the drop downs yet but certainly we would be irresponsible if we didn’t think about that on behalf of both sets of investors.
You know I would be practicing medicine without license if I answered that question but that would obviously be a consideration. Are you telling me -- if were to...
Distributing the units like owning a suburban transaction just by virtue of distributing those units is not a taxing event. We have work to do. If we were to go down this path to distribute those NRGMs but I think I would just use suburban right now what we did there as an example.
That was not a (inaudible) The distribution of those units itself was not a taxable event.
Just a question on the drop downs. I think you had mentioned you would like to see those in fiscal ’13. I wanted to follow up and just so that I am clear, does that include Tres or do we still need to see some improvement in Tres before that’s considered a drop down. I think you had mentioned that at Tres we are probably at a bottom at this point.
You know I think -- I don’t necessarily think we need to see improvement in Tres. We are not -- I think that business is already in our minds, we think it’s at a bottom. We think that in a drop down scenario, you are going to have two board committees regardless. It’s going to be at a fair market type valuation relative to not just the performance today but ultimately in the expectations for growth or improvement in the operations there. So we are not -- there is no magic number relative to having ultimately to see us recover the investment that NRGY made.
When we took NRGM public, one of the things we said about the assets that we placed into NRGM, was that those were -- those cash flows we felt, we believed were stable, predictable recurring cash flows. And those are the characteristics really of cash flows that we are after for NRGM and when you think about the two businesses up there, we have got NGL supply and logistics which has been stable and growing. And you have got Tres. Tres, as we said that we do believe it’s bottomed out. So I think we see kind of this steadiness there. But that’s something we have to look at all the time and that will be part of the board process because we have made that kind of statement.
I was curious if you could give some color as far the growth CapEx for next year. How that might fall off for different projects or just any color around that would be helpful.
Yeah, so downstairs at NRGM’s level, that $80 million to $100 million is really, that is about in the neighborhood of $40 million of capital that we will complete in the very near term relative to finishing up the Marc I. There is about $18 million to $20 million of capital related to our Finger Lakes NGL storage expansion, the Watkins Glen NGL expansion. And there is about $19 million of CapEx around the Rangeland, COLT Hub acquisition. And then the remaining balance of what's left is kind of cat and dogs. Does that answer your question? At NRGY you can see the difference between those as very -- not a great amount of CapEx. The majority of that is going to be on our [Copeno] and the Tres [Hetterigs] extension project that Ron spoke of earlier.
I have a question about the authorization, the repurchase of stock. Have you bought any stock yet since the announcement and who do you evaluate share repurchases versus acquisitions? What's the metrics and how do you go about that process?
The answer to the question relative to repurchasing, we have not repurchased any of that stock. I mean we put that program in place as we looked to execute on and complete the Suburban transaction and ultimately distribute those units out. We were cautiously concerned around the distribution of the units and ultimately the communication around investors continuing to receive effectively $1.50 in cash distributions from the combination of NRGY’s direct distribution as well as the distribution from SPH. You know I think that was probably primary concern around that and we have definitely we can adjust and we think about whether we repurchase units. I think relative to deploying capital up at Y for acquisition opportunities and potentially raising equity, obviously it’s a balance. We would be very judicious about using any Y equity, whether it’s strategic or whether we step in to help M otherwise complete an acquisition. And right, John and Brooks if you have anything you want to add to that.
I think Mike is exactly right. That was our mindset when we put that plan in place. The balance, if we did anything, it would really be on an opportunistic basis at this point.
Is there a reason why or have you guys thought about how to get more liquidity into NRGM and as you do these drop downs, why don’t just take all cash in and you can buy back stock or whatever you want to do, pay down the debt at the Y and just get more float down to M because I think it’s so illiquid it’s just kind of like -- not that Y is that liquid either but M is so illiquid it’s almost (inaudible) buying?
It seems people like it, it sounds some pretty tied hands. But I mean obviously as John pointed out down the road there are things that we are thinking about relative to the possibility of enhancing and helping. We just placed a private placement which has a lockup in it around the Rangeland COLT acquisition. But our mindset is, and we understand the liquidity and the lack thereof around NRGM and ultimately as we execute forward, I think that’s something that as an ancillary benefit to executing our growth will, we should solve some of that issue.
I think, just to add to that a little bit. You know the drop downs and that Y taking back units, that we are maintaining a strong balance sheet at NRGM by doing that without creating overhang on stock price for current shareholders. And I think the idea around whether it was something we would do or not, we will find out but distributing those units out to NRGY unit holders would also, we believe create greater flow in the stock too. So that is one way to do it. We are trying to make sure that we are both balance sheets here.
I think we will give more liquidity overtime. I mean we are almost at the one year anniversary of the IPO. Haven’t been S3 eligible and we will expand that balance sheet and do some things as Brooks said, that will definitely improve the liquidity and hopefully attract more institutional type investors.
If there are no further questions, I just want to reiterate and thank everyone for being here today. Thank you for those on the webcast that may still be listening. We appreciate your time. Thanks again.
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