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Williams Partners L.P. (NYSE:WPZ)

Q3 2013 Earnings Call

October 31, 2013 9:30 am ET

Executives

John Porter - Head, IR

Alan Armstrong - CEO

Don Chappel - CFO

Frank Billings - SVP, Northeastern G&P

Allison Bridges - SVP, West

Rory Miller - SVP, Atlantic Gulf

John Dearborn Jr. - SVP, NGL & Petchem Services

Fred Pace - SVP, E&C

Analysts

Christine Cho - Barclays

Holly Stewart - Howard Weil

Stephen Maresca - Morgan Stanley

Ted Durbin - Goldman Sachs

Carl Kirst - BMO

Bradley Olsen - Tudor Pickering

Curt Launer - Deutsche Bank

Becca Followill - U.S. Capital Advisors

Selman Akyol - Stifel

Operator

Good day, everyone, and welcome to The Williams and Williams Partners Third Quarter Earnings Conference Call. Today’s conference is being recorded.

At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead.

John Porter

Thank you, Devona. Good morning and welcome. As always, we thank you for your interest in Williams and Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our websites, williams.com and williamslp.com. These items include yesterday’s press releases with related schedules and the accompanying analyst packages; the slide deck that our President and CEO, Alan Armstrong, will speak to momentarily, and an update to our Data Books, which contains detailed information regarding various aspects of our business.

In addition to Alan, we also have the four leaders of our operating areas present with us. Frank Billings leads our Northeastern G&P operating area; Allison Bridges leads our Western operating area; Rory Miller leads our Atlantic-Gulf area; and John Dearborn is here from our NGL & Petchem Services operating area. Additionally, our CFO, Don Chappel is available to respond to any questions.

In yesterday’s presentation and also in our Data Books, you’ll find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks, and you should review it. Also included in our presentation materials are various non-GAAP measures that we reconcile to generally accepted accounting principles. Those reconciliation schedules appear at the back of the presentation materials.

So with that, I’ll turn it over to Alan Armstrong.

Alan Armstrong

Great. Good morning, everyone, and thank you, John. Starting here on Slide 4, I love this cover that our IR team came up with -- it really depicts all the tremendous amount of activity and construction and project development that we have going on right now at the company and are currently managing, and certainly this is what is will support the tremendous cash flow growth that supports our 20% dividend growth at WMB. It also I think is important to note this heavy CapEx burden also weighs heavy on our coverage during this super cycle of investment opportunities that we’re thrilled to be a part of right now.

Before I get into the slides, let me just very quickly remind you our strategy that continues to guide all of our actions and certainly our investment decisions. And so our strategy which is to be the premier provider of large scale infrastructure to design to maximize the opportunities created by the vastly greater supply of natural gas and natural gas products now known to exist in North America’s unconventional resource plays. This is underpinned by our scale which we see as a competitive advantage in all the areas that we operate, so wherever we are you will see us be big. And if we can’t be the number one or number two in an area you won’t see us going in a space like that because we think to have superior returns, you got to have the advantage of scale that allow you to connect your customers to the best market. So we want our supply connected to the best markets and we want our markets connected to the best supply, and we want to be the infrastructure in between that continues to fuel this tremendous opportunity here that we have here in the U.S. to take advantage of low price natural gas, natural gas liquids and the olefins derivatives off of that.

So moving to Slide 5 here, I'm not going to spend a whole lot of time on this because it’s really is just a overview of this brief presentation, but here is what we’ll cover here this morning. First of all, I’ll talk a little bit about our better than expected third quarter performance and the drivers for that be and also shows some detail on how we are accounting for the impact of our Geismar outage.

Next I will also reaffirm our 20% dividend growth profile at WMB while lowering our distribution growth rate to the bottom of our earlier stated range for 2014 and 2015. So we’re at the top end of the range here in 2013 and we will be moving to the bottom of that range with that 6% to 8% range for 2014 and 2015. And of course that is designed to drive better coverage metrics at WPZ and along with something we’re excited to announce and something we’ve been working on for a while which is to provide you some detail on our Canadian asset dropdown and that would be the existing assets that we plan to dropdown in January of 2014.

Next, we’ll review some drivers of our tremendous 60% DCF growth at WPZ throughout this guidance period. And then, finally, we’ll review our project’s Execution Scorecard that is so critical to our success and we continue to show you. And so it’s critical not only for this guidance period but even beyond our guidance period as we continue to develop more and more fuel for our growth beyond 2015.

So moving on to Slide 6 here. This is an overview of the third quarter and it certainly was a good quarter and better than we expected on many metrics for the quarter. And so the thing I’d tell you I’m most excited about is the way our strategy is working and finally in this quarter we saw our growth in our fee-based revenues begin to overcome the continual slide in the NGL margins. And so you can see there $61 million increase in the fee revenues and that’s a 3Q of 2013 compared to 3Q of 2012, and so really thrilled to see that. In addition to that, despite the tremendous amount of development and effort we’ve got going into growing our business, we’re also able to control cost and continue to lower cost on that same comparison of 3Q 2013 to 3Q 2012.

So at WPZ, our DCF was up 20% as compared to 3Q of 2012 and this was driven by that $61 million increase in the fee-based revenues at PZ. Primarily this was driven by the tremendous growth in the Northeast and on Transco. And also just to put that in perspective for you that means a 9% increase in our fee-based revenues more than offset a 30% decline in our NGL margins during that period. Also, something very excited about is the $19 million reduction in our O&M and G&A again in the face of tremendous growth across our system.

Additionally our WPZ maintenance CapEx was down $50 million as compared to 2012 and we still are spending over $310 million this year. And these maintenance capital expenditures and we certainly and compared to 2012 one of the drivers for that in 2012 we got a lot of spending in our -- the asset integrity and the Clean Air Act issues related to our gas pipelines, and so we got a lot of bad out of the way in 2012. And in addition to that our maintenance capital on our Midstream assets was actually down more significantly and this was driven by lower well-connect cost out West and as well as we’ve been making some smart consolidations out west and retired some of our older higher cost assets like our Lybrook Complex in the Four Corners Area and that allows us to obviously to then to not have to spend the money to maintain those assets over time.

We continue to invest as required to maintain these safe and reliable assets and, in fact, we will invest over 35% of our segment profit from our pipes back into the proper maintenance of our two major gas pipelines Transco and Northwest Pipeline. So the negative for the quarter certainly was the lack of contribution from our Geismar facility and it only contributed $15 million to the DCF for the quarter. And this represents about a 13 day period between the 60 day weighting period on the BI and the planned 50 day turnaround.

And we’ll show here on the next slide we show some really good detail on how that works out. It’s certainly, fairly complex the way we’re accounting for that Geismar impact but I think it’s really important to note here that, that even with Geismar with this 20% growth in DCF we only got $15 million of that 20% improvement out of Geismar for the quarter. So really truly a strong DCF for WPZ during the quarter. And we’ll show here on Slide 7, now moving to Slide 7, you can see what we show as the impact from Geismar.

And so I’ll focus your attention here to the $79 million in the bottom of the second column and what that represents is the negative impact or the delta that we estimate we would have seen, we did see in the quarter versus what we would have seen if Geismar would have been up and running on a normal basis in the pre-expansion mode.

So to keep this simple on this chart you can think about this business as about $1 million per day of impact to our DCF and in the pre-expansion mode. And so you can see there that the 60 day waiting period accounts to a total of $60 million of impact in 2013 and you can see the 50 day turnaround amounts to $50 million of the impact looking over there to the right column.

So really only about 13 days of profit in the third quarter associated with the business interruption claim that we submitted for the third quarter. And this combined with the receipt of an actual insurance payment of $50 million related to the incident during the third quarter allowed us to record this $15 million of DCF in the third quarter.

So we also show on this slide how that has been handled in our accounting for both GAAP and adjusted numbers and we provide some additional detail in the appendix. So anyway, fairly complex but bottom line here is we think the -- this hurt us having Geismar down for the third quarter hurt us by about a total of $94 million offset by the $15 million of DCF that we reported to in the quarter.

Moving on to Slide 8 then, this is the -- a little more detail on our Canadian asset dropdown and so we’re certainly excited to be announcing this. This really comes at the startup now of our last big expansion our ethane, ethylene recovery facilities that are now in operation at Fort McMurray. And so we’ve got pretty big window here now between the next big tranche of assets that will come on which will be the Canadian -- sorry, the CNRL Horizon facilities and the PDH facilities. So this is a nice window for us to dropdown these assets that are now up in cash flowing existing assets that are up in cash flowing.

So a little bit about this business, certainly as we’ve explained before we’ve got great competitive advantage in this business and because we really are the only parties up here that are taking the off-gas and extracting these highly valuable products out of the off-gas and we’ve got the right assets, the right experience and the right operating team to build to continue that. And so we’re excited about that continued competitive advantage leaving further growth for opportunities like Syncrude in the future.

We also are expecting about $200 million of DCF from these assets in 2014 and 2015. And one thing I think is really unique about these assets is they were quite either though they are typical processing plant in fractionation they have such a tremendous resource upstream of them that is invested by the upgraders that we really have very little capital required to keep these assets, keep the free cash flow coming out of these assets partly due in fact we don’t have any well-connect cost, we don’t have to go, secure new supply for these assets, and partly because these assets are relatively new as we’ve been expanding these assets over the last 10 to 15 years.

So very excited about being able to do this and we will be funding this through WMB taking back 100% paid-in-kind units. So on a transaction this will add DCF coverage for both 2014 and 2015 and as many projects come online this will continue to support our industry leading dividend growth beyond 2015 when the PIK units convert. So said another way certainly the PIK units give us some room on our coverage here, so we think this is a really smart transaction for WMB and bridge as to when this tremendous amount of capital investment that we’re making over this period about $8 billion really starts to kick in 2015 and beyond.

So the plan to dropdown of these currently in-service assets is subject to the successful negotiation of a transaction between Williams and Williams Partners and because of that we’re not going to be pinning down a price, a transaction price at this time, but I will provide you a little more insight in what we’re expecting here. We certainly recognize that a portion of these assets have commodity risk and as a result of that the multiple will be -- need to be lower than what you might normally expect.

And so just to decode that a little bit at this point we expect that multiple to be below a 7 multiple for this transaction. And so not too different than the kind of multiples, all-in multiples that we saw with the ethylene cracker even though I’ll remind you that these assets, for instance, the ethane and ethylene business are backed by some fixed rates in terms of capital recovery for the ethane and ethylene projects.

Another really important point I would make on this slide is that our projects like the CNRL Horizon project which is underway and we’re certainly up and spending capital dollars on that and as well as our PDH project and potentially the Syncrude processing expansion are staying at WMB and will be great future dropdown candidates for WPZ. And in fact just to kind of put that at all in perspective for you, WMB continues to build out a tremendous backlog of future dropdown candidates in both Canada and the Gulf Coast Petchem area that we’ve talked about in the past.

And so of just the projects that are approved and underway we’ve got more than $2 billion of additional dropdown candidates for WMB that we dropdown two WPZ. And in addition to that we also have the exciting Bluegrass and moss like JV with Boardwalk. So we are building out a tremendous amount of dropdown opportunity and that doesn’t even include things that we’re continuing to develop like the Syncrude opportunity in Canada as well. So plenty of continued growth for WPZ as WMB continues to develop some major projects.

Moving on to Slide 9, you can see here the very impressive story of DCF growth from 2012 really as we increase $231 million from 2012 up to $1.72 billion in 2013 then in 2014 going up $630 million to $2.35 billion and then up another $435 million in 2015 versus up to $2.78 billion.

So some very impressive growth going on in this space, and I would just say couple of key points here. First of all the coverage ratio that you see here does assume the distribution increase of the 9% this year and 6% in 2014 and 2015. So the coverage is over and above that distribution growth and importantly in 2014 and 2015 we are assuming no additional IDR waivers from WMB. So really working here to get WPZ to a position of a coverage ratio that we’re comfortable with and certainly the Canadian dropdown and the reduction in the growth rate are the key tools that we’ve employed here to accomplish that. The drivers throughout this entire period, as you can see, are the tremendous amount of portfolio projects and the one dropdown that we have built into WPZ right now.

I’m also going to make a few notes here on just -- there have been some confusion I think on the IDR waiver for 2013 and just to be a little clear on that. We are only planning on using $140 million of the $200 million that we previously announced as a cap. And so what we did say was that we would contribute up to $200 million of waivers from WMB to WPZ as required to maintain a 0.9 coverage ratio. The good news is because of our better than expected performance at WPZ here in the -- both the third quarter and throughout the balance of the year that we do not think that we will need to contribute anymore than another $50 million on top of the $90 million that is being put forth to-date.

So anyway, good news on that for both the PZ side and the MB side. Another comment I’ll make here quickly is on the capital side and you will see in the CapEx changes as you review them you’ll see we’ve added about $375 million or about 4.6% increase over the $8 billion of spending during this period. And there is really two primary drivers for that. First of all, a $200 million increase in our Gulfstar One project, and let me remind you that Williams Partners has a 51% share of that project so that would be $102 million net to our interest. And so this brings the real net increase in capital spending to about 3.5% over this $8 billion. And in addition to that though to really describe what’s causing that we have two new Transco projects have been added to guidance during this period as well. And so Transco just continues to see tremendous opportunity on the market and in particular of expanding as people continue to build a demand for these very low price natural gas and the tremendous growth opportunities that the Eastern Seaboard represents for Transco.

And so let me move on now to Slide 10, and this is our scorecard that we continue to show you and just a few things to highlight here in terms of changes to this. First of all, you will see that the third quarter projects, which was the Canadian ethane recovery and Transco’s Northeast Supply Link are now online and so we’re excited about that. The investment in ACMP I would tell you is not listed here, so we have a lot of capital here, but in addition we have growth coming from the ACMP investments.

And also remind you that with the exception of the Geismar expansion project and the Canadian projects, the PDH and the CNRL Upgrader, these remaining projects are all backed by fee-based revenues. And so that is what’s continuing to drive that increase in fee-based revenue. I think what’s really impressive her as we continue to add in fact we’ve added one project here the Hillabee Expansion to this Transco portion but we also have a smaller project that’s not listed on here but we continue to really build out the Transco expansion projects and we think those are great projects for both WPZ and then ultimately flow into WMB’s cash. So that’s the picture here.

I’ve already talked about the Gulfstar increase and I think that’s the majority of the issues, you will see in the Northeast our spending is actually pretty flat, a little bit of movement between the various asset areas but generally pretty flat.

Moving on to Slide 11, and this is the picture of the Northeast. Certainly, we’re making a major reduction in the rate of growth for OVM and but I certainly want to keep this in perspective here. We have now grown these volumes in year-to-date 2013 versus year-to-date 2012 by over 80%. So despite a lower projected growth rate at OVM, our growth here is tremendous, it continues to be tremendous and we couldn’t be more excited to be and what we think is the growth area in the U.S. for -- from load to Marcellus and the Utica.

And so this growth, as you know, does not depict our exposure, economic exposure that we have to both ACMP and Blue Racer and it also doesn’t include any growth from Three Rivers yet we are still showing a 73% growth in this period from 2013 through 2015.

So we’ve lowered, as you can see there, pretty significantly OVM but the primary drivers of that being a lot of the private equity groups that were invested out here have now sold out to parties like Chevron and Statoil, and I would just say that they are more patient investors and I think they are waiting to make sure that the infrastructure is available to get both their gas and their NGLs to market, and so we think they obviously make great customers for Bluegrass and but they’re going to look at these resources and make sure that they can get their products to market and to good markets before they go into more aggressive drilling programs out here. And so that’s really one of the major changes here as we shifted from more aggressive independents owning some of these resources to more patient investors like Chevron and Statoil.

Moving on to Slide 12, this is just a big list of all the various accomplishments and things that continue to go on here, certainly the Bluegrass open season and the continued growth on Transco are kind of the big highlights that I would point out to you here. The Atlantic Sunrise open season was overwhelming I guess is the best term we have to describe it and really very, very excited about the kind of response and how quickly we’re going to be able to bring that to closure given the very strong response there. So it’s nice to be in a position of having to figure out how you’re going to size the project and fit in all the demand that we saw from that. So that’s a very exciting development during the period.

Additionally we hit a new record high in the Northeast of 2 Bcf per day on a monthly average during the third quarter. And as well ACMP announced earlier is I’m sure you all saw that they were raising their LP distribution up 23% in the third quarter versus the third quarter of 2012. And that is big news for us because that really accelerates the Williams GP interest into the high splits a lot quicker than we were planning on. So that investment opportunity is proving out very well for us. And we continue to be very excited about our relationship with ACMP’s management team and our ability to continue to support their tremendous growth opportunities that they have in and around their business. So, couldn’t be happier with the way that asset or that investment is performing and certainly thrilled to see the high quality of the ACMP management team that continues to perform very well.

Moving on here to the closing slide, just remind you that we are all-in relative to this natural gas infrastructure super cycle, we think it’s the right place to be. We like a commodity that we think is solo compared to crude oil and other commodities that it is going to continue to drive demand and ultimately that demand is going to drive contingent supply growth. So we really are bullish on our situation where we sit and you’re going to continue to see us to invest heavily into this space while this opportunity to build out this major infrastructure that will be here for many decades to come gets built and we don’t intend to back off of our heavy investment cycle while the opportunity presents itself.

We also are continued to be excited about our 20% WMB cash dividend growth through 2015. And I think if you really stop and look at how all of these big projects are coming on in 2015 and the continued growth cycle that we see beyond that I think you will see that we’ve got good reason to continue to support very strong dividend growth beyond 2015. And again, we just remind you that we’ve got over $1.1 billion of DCF growth in 2013 through 2015, and this is not based on acquisitions that we might speculate on is not based on projects that we’re speculating we might win on these projects that we are out developing and building right now and all identified and contracted. So very excited about where we stand today, excited about some of the changes we made here for the third quarter and look forward to hearing your questions.

Question-And-Answer Session

Operator

Thank you. (Operator Instructions) And we will go to Christine Cho with Barclays.

Christine Cho - Barclays

In last quarter’s data book you guided towards $110 million to $200 million of segment profit plus DD&A for the WMB NGL and Petchem Services in 2014. Can you help us reconcile between that number and the $200 million DCF number you gave for the dropdown? Is most of that driven by the higher propylene prices you are now using in commodity assumptions?

Don Chappel

Christine, Don Chappel. Yes, it’s largely an improvement in margins in Canada as well as lower expected corporate allocated cost, and that’s just based on formulas that we continue to implement. So our new organization structure that we announced at the beginning of the year is I think bearing some fruit and our costs are somewhat less than perhaps what we expected before and the Canadian business is getting a bit less than that. So I think those are the -- or the NGL Petchem Services business I think a more broad statement is getting a bit less of that. So those are the primary drivers.

Christine Cho - Barclays

Okay. And then how should we think about the potential timing for the additional dropdown that Canada, two other off-gas processing contracts the one maybe two PDH facilities maybe Bluegrass. Would you be open to drop it as soon as it’s cash flow generating which may not be a lot in the beginning or would you wait for it to little more mature?

Don Chappel

I think it’s too soon to answer that question. I think certainly the eligible to drop at anytime quite frankly, but we think that the right answer is to build it at Williams and then drop it once its in service. And I think we have to take a look at the cash flow profile and determine if that’s right on start-up or if it’s sometime after start-up as the cash flows ramp-up. So I think that’s a question that ways out, that's a couple of years out at the earliest and we will continue to study that.

Christine Cho - Barclays

Okay. And then what are the tax implications for dropping the Canadian assets? Are you guys subject to any repatriation tax?

Don Chappel

We expect and I think you will see it in our 10-Q to record a tax provision of just over $200 million, cash taxes of about $140 million in the near term. So it’s really an acceleration. We expected at some point that we have repatriation and we have a tax to pay. This will accelerate those cash taxes to the tune of $140 million. We’ll be able to use excess cash balance as cash balances we have on hand to pay the $140 million. And then after that, we’ll have the Canadian tax. Right now the Canadian tax rate is very low perhaps zero because just much like in the U.S. we have high capital spend and accelerated depreciation that’s shielding taxes. But at some point, we will Canadian taxes and we will get a U.S. tax credit for the taxes paid in Canada and we will pay the differential of U.S. tax. So a fairly -- so the one-time cash tax cost is about $140 million and then beyond that it will be some incremental amount of U.S. tax over and above what we would typically pay in Canada. Canadian statutory rate is 25% so again it’s a factor but it’s not huge relative to the value of the assets.

Christine Cho - Barclays

Okay, very helpful. How comfortable are you with the new numbers at OVM? Are we largely derisked here and also the other segment costs and the Northeast segment seem to be really high. Is there anything one-time here in nature or is this kind of more of a run rate we should be going off of?

Frank Billings

Sure. This is Frank. I think on the relative to the Northeast and the volume, I would say that we have probably derisked that some. Really what I would say is the primary factors I would call 2013 kind of the lost year, I mean we really didn’t get much volume growth and basically what we are anticipating and what our producers are projecting this kind of push kind of what we’re expected in 2013 and we kind of rolling most of the drilling plans over.

On the cost side if you look quarter-to-quarter we did have it looks like a pretty significant increase in quarter-to-quarter other segment costs and expenses around $22 million, but in that number is some of that 9 - the $9 million adjustment that’s down below and we have the contingent liability that we booked. We also had some slippery payers that hit us in the third quarter as well as some write-offs of some investments that we started to undertake in OVM but then didn’t fall, through with those what we change the project scopes so we had some cost that we had that we’re capitalizing, we’re trying to take to expense. So I think going forward, we will have a run rate that's less than what we saw in the third quarter.

In OVM, we have a liquid system, a gas system processing plant and fractionation and we really kind of set up our organization to have some of those assets in place in 2013, those assets aren't in place to 2013. We won’t be looking at a material or budget staffing increases as we get into 2014. So really we’re going to kind of hold and redistribute our once our asset -- and we will have better, that’s better to find after the construction and commissioning is completed. So and we did have some items in Q3 that drove that number up but our run rate should be less than that.

Christine Cho - Barclays

Okay, great. And then last question from me, the spread between Texas and Louisiana as link prices have obviously been a focus given the pipeline that's in the two states are down, how are your insurance proceeds going to account for this? I think it was initially thought that the pipeline would be down through year end but now I’m hearing that it’s going to be pushed out further than that.

Don Chappel

Christine, this is Don. The insurance policies provide coverage in terms of the loss value of production. So we’ll calculate, we know the loss in production is, we’ll take a look at the market prices and that will be the basis for our claim. With respect to the pipeline that’s something we’re continuing to study to determine what effects it may or may not have. So I’ll just pause there and perhaps I don't know if Alan or John want to add anything regarding pricing the pipeline.

Christine Cho - Barclays

Well just because I ask because are you going to be getting Mont Belvieu pricing or Louisiana pricing, I mean there was like a $0.20 spread between the two points last time I checked.

John Dearborn

Yeah, and perhaps I could make some comments there, this is John Dearborn. If we look at the dynamics in the market there right. With our plant down in Chevron Evangeline pipeline out of service, the Texas market has got length and Louisiana in short, right. So that’s what we always see and that’s what’s driving the premium between the two markets.

As we look forward and we bring Geismar backup and we expect that at sometime Evangeline will be back in service that’s a market dynamic is going to diminish in it’s significance, but let’s remember also that second quarter next year we move into the industry’s ethylene cracker turnaround season and I believe there are about four crackers that go into turnaround there. And so as we take a look at all of that in total, we are looking forward as strong demand that which I think is going to support very strong ethylene margins into next year and through next year if we could take you to that line of reasoning per se.

Christine Cho - Barclays

Okay. That’s helpful. Thank you very much.

Don Chappel

Again this is Don and I just remind everyone that this pipeline outage is a short term issue and we don’t expect it expand all that long.

John Dearborn

And recall also that's a Chevron asset. So I think for the true story on that go to Chevron for that as well.

Operator

And we’ll go next to Holly Stewart with Howard Weil.

Holly Stewart - Howard Weil

Just maybe a high level question on the Northeast infrastructure issues I think you guys are probably and one of the better or have one of the better advantage points on the price side. So what are you seeing in the Northeast, what alleviates the differentials and what’s your view of the differentials going forward?

Alan Armstrong

Holly, I will take that. This is Alan. First of all I think there has been a lot of focus on just the northeast dry area and certainly there is more infrastructure over in the southwest and over in the Utica area, but we’re certainly seeing continued a lot of development over there as well. And I would say a lot of pressure has came on here in the third quarter from two factors, one being that the certain pipes were not yet open, so Tennessee expansion wasn’t online yet and so that we think will help alleviate. But as well a lot of new gas came on in the quarter that wasn’t necessarily from drilling but it was from infrastructure tie-ins not necessarily on our systems but some of the adjacent systems really worked off a lot of the well-connects and a lot of the pending completions. So we saw a tremendous amount of gas come on, trying to come on in the third quarter and it was coming into the phase of a market that was lower.

And so the Northeast Supply Link project is now up and running and so on Transco so that’s 250, I can tell you that’s hardly a drop in the bucket compared to the kind of demand that we’re seeing for the infrastructure being built out of the area. But I do believe that the fall shoulders out there are going to be a little worse than the spring shoulders because this is kind of a rare situation up here where you have the Leidy storage which is a very large market area storage that refills in the spring but of course it was full in the fall, and so nowhere from that gas to go either into those local markets or to the south.

I think pipelines like Transco are now -- got plenty of support for new infrastructure to debottleneck systems to build the carry-markets to the south and certainly the Atlantic Sunrise open season was indicative of that and as well of course the constitution project we think will alleviate some of the challenges up in the Northeast area. But I would just say this, people that are not paying attention to that and not planning for their capital expansion or taken some pretty big bets I would say and some pretty big risk. And those that are continuing to plan and plan well I think we’ll be the winners at the end of the day and we’ll be able to access growing market on systems like Transco to the South.

And so I think we’re getting after and as usual the market, we tend to wait a little too late to get the infrastructure build and we probably be having the same discussion on Bluegrass here in 2015 before that capacity comes on to get the NGLs out of there as well, but I certainly think the market has gotten a strong signal from the gas-on-gas competition it saw this quarter and it seems to be responding to support contingent infrastructure development out of the area.

Holly Stewart - Howard Weil

Got it, okay. And then I guess you gave an explanation for I guess weakness in the Northeast volumes compared to maybe what you had initially forecasted. In terms of these new customers or now the majors are -- what are you assuming for growth in 2014 and 2015? I guess my point are you comfortable that your new targets have some other plans factored in?

Alan Armstrong

It is, it’s really kind of built from the ground-up looking at the drilling plans that we’ve discussed with the producers and so we feel pretty comfortable. I would certainly wouldn’t try to tell anybody its not without risk because there is a lot of contingent infrastructure development to be built out there, but I would tell you that we feel pretty comfortable with the schedule and the detail that we built behind the volumes at this point, and so really is kind of a grounds-up review from each of our producer in their drilling plans out there.

I do think there are perhaps some opportunity to improve on that if we saw some better pricing signals and people become convinced that Bluegrass is going to be get built and we might see some even better development into the 2015 timeframe as people gear up for that.

Holly Stewart - Howard Weil

Okay. And then you kind of led me into my final question. Can you just maybe explain the open season for Bluegrass and how these commitments will really work on the Bluegrass pipeline and the LPG terminal?

Alan Armstrong

Well, I would just say that the open season for the pipeline is completely separate from the fractionation and the export terminal discussions. Having said that, we recognize that customers don't want to a pipeline to nowhere and so that’s why we’ve been working so hard at developing both the storage, the terminal, and the export facilities is that we got to be able to provide customers with a comprehensive solution. And I would -- the thing I’m fairly encouraged by in that regard is with the discussions we’re having on the export side we’re seeing interest in customers wanting to know where that supply is going to come from as well.

And so I think the markets really starting to come together in terms of the supply side and the demand side, and we see that as one of our critical roles in the industry right now is bringing together that strong demand that we’re seeing from international players back upstream to our customers on the upstream side and being party providing the infrastructure in between.

Holly Stewart - Howard Weil

Okay. So it’s not all comprehensive in terms of it all getting built?

Alan Armstrong

Well, I would say that at the end of the day people are going to want to know what their frac deal is but that’s a -- just because of the regulatory process, that’s a bifurcated process. So we deal with them in the open season and we make sure that everybody has a chance to weigh in on the capacity that they want and the terms of the capacity they want on the regulated side. And so we make sure that’s a non-discriminatory process. And then second to that then there is a discussion around what people’s needs are for storage, fractionation and export capacity. But I would say that most customers are going to want to know what their deal is on both sides of that. So on one end they are separated for regulatory purposes, on the other hand people need to know what their downstream services are going to be.

Operator

We will take our next question from Stephen Maresca with Morgan Stanley.

Stephen Maresca - Morgan Stanley

Just sticking on lower amount and OVM for a second to be more specific you took Northeast adjusted segment profit in DD&A down about 20% in 2014 and 2015. Can you help us understand what changed so material in such a short period from last quarter’s forecast to now? I know you touched upon it, Alan, but is it as simple as just your drilling plans off because of the change in ownership? And as a subset to that, it seems like you drop the '16 and '17 kind of bar chart forecast you have in the slide in terms of gathering volumes for the Marcellus. This is out of sign or do you not feel comfortable forecasting that anymore in light of the changes and ownership from private equity to bigger majors?

Alan Armstrong

I would just say our -- what we are seeing from the majors is, as I said, just a more careful effort on their part to make sure we maximize the NPV of their reserves and not just quick drive towards IPs and volumes and so -- sorry, IPs and reserve growth. And so I’d just say that we’ve -- what shifted really was having sitting down and wanting to make sure that we weren’t investing capital too far out in front of the reserve packages that we’re seeing there and not taking on additional risk.

And so that resulted in sitting down and getting very detailed granular analysis on what their drilling plans were. And as you know, that’s little harder to predict because of the motives of the majors are more around allocating capital around and so it’s a little harder to predict and somebody just has one resource to go develop.

And so I would just say we’ve gotten a lot more conservative in our approach towards that forecast and it just built from the ground-up. And that probably is the major shift that we made, Stephen, was moving from a resource capability play to a detailed analysis of what the producers are actually doing in their actual drilling plans.

Don Chappel

And Steve, we ceased to project 2016 and 2017 given the challenges we’ve had in projecting the next couple of years. So we’re really focused on projecting 2014 and 2015 and just conforming the volume forecast to our guidance period and really not trying to get too far out given all the variables that we see in the Northeast.

Stephen Maresca - Morgan Stanley

Okay, appreciate that. Moving to Bluegrass and I do have a couple of questions here. Alan, do you have the same level of confidence in this project getting completed as you did on the last call given the large competitive project proposal? And can you talk at all ballpark types of project returns you would expect? And then I have a second one just on the funding after that.

Alan Armstrong

Well, I would say on the confidence level I think this might surprise some people but the confidence -- my confidence level is not really all that driven at this point by the competing project just because we think we’re so far ahead in terms of development of the project, details and how far ahead we are in terms of getting project developed. I think the -- so I would just say that’s not really that big a factor frankly. I think the challenge that still remains is producers knowing their drilling plans being committed to the drilling plans. And so I think we may get a lot of commitment but we’re going to need to be weighing how solid that those volumes would be and how much we can count on those volumes being there. And so that’s what we are in the process of doing with the open season.

And as I’ve said before we’re very excited about Bluegrass. We think to really key piece of that infrastructure for the Marcellus and the Utica, and we think that it really, really needs to be installed at the end of 2014 to protect our investments on the upstream side and other investments or other more indirect investments that we have up there. So we think it’s very important and we need Bluegrass is the only one that can really meet that kind of timeline.

So that gives us lot of confidence but we’re also -- we’ve got a lot of projects to invest in and we’re going to make sure that it’s a sensible investment for us before we plough, start really ploughing the big money into it in the first quarter of 2014.

Don Chappel

Steve, this is Don. In terms of financing, again we have a partner at Bluegrass and I’d also note that we’ve been approached by others, industry players and financial players that would like to invest in the project and we may or may not choose to partner with others. But beyond that will be a combination of debt and equity to maintain our credit rating goals, which we previously consistently espoused these investment grade ratings.

Stephen Maresca - Morgan Stanley

Okay. One follow-up there, have you thought about something at all that doing something with your access GP, LP state to monetize that and create some liquidity or is that not something that’s on the table right now?

Don Chappel

I think all of our assets or things that we evaluate all at a time and certainly those are assets that we continue to look at as well. So I certainly don’t want to create an expectation but we certainly look at all the levers that we have to pull as we look at potential financing.

Operator

And we’ll go next to Ted Durbin with Goldman Sachs.

Ted Durbin - Goldman Sachs

Not to state too much on Northeast G&P, but would you have a pretty significant cut in EBITDA but not really any change in the CapEx forecast from what I can tell from last quarter. So we’re effectively saying we’re getting lower returns on capital, I’m missing something. Is there a reason why the CapEx budget may not have gone down given the slower volume ramp?

Frank Billings

Yes, this is Frank. What we’ve done is we basically cut more of a capital out on the out years. We’ve taken out the third train, frac train, we pushed out the second, third and fourth processing plants. So we kind of basically we focus on installing the - I’m going to say those foundational assets the second frac expansion, the stabilization plant with the ethanizers, the ethane pipeline. Once we get all of those assets in place in by 2Q of 2014 we will pretty much of that majority of those what I would say is the foundational assets in place. Some of the assets' installed costs have gone up some, but that’s part of the reason we kind of had, we haven’t had the 2014 capital change. If you look most of it shifted from 2013 to 2014 and that’s the representative of the shift in in-service date and then most of our growth capital have been pushed out to match the volumes being pushed out.

Ted Durbin - Goldman Sachs

Just shifting over to Geismar, can you give us an update on where you are with some of the regulatory side of that in terms of the whether its OSHA really the folks that are in there looking at it?

Alan Armstrong

Sure, I will have John Dearborn answer that for us.

John Dearborn

Sure. And thanks very much for the question. Our relationship with both the agencies remains extremely strong and excellent. We are committed to keeping it up certainly that way. With the government shutdown that we all witnessed here over the last few weeks or so we’ve suffered a bit of a delay as that shutdown that CSP and the OSHA worked for a bit of a while. However, prior to that shutdown we got all the necessary protocols in place to continue our work around the propane, propylene fractionator that was damaged. And so we’ve continued our work and we don’t expect to suffer any delay in what we’re doing as a result.

One of the other things though that I would like to bring to your attention in order to continue to build this relationship with OSHA and CSPs you might have noticed that we’ve released the findings of the Williams investigation. And we’ve kind of taken care to communicate those findings to all the important stakeholders, of course our employees being one of them, but we took the time and effort to communicate that to OSHA and CSP, and of course they were grateful to us for that.

Bottom line is we still expect OSHA to issue their report around the beginning of the New Year and that’s the next important milestone I think relative to the federal regulatory agencies.

Ted Durbin - Goldman Sachs

And then last one from me is just on the cost. You did actually take a lot of cost, it looks like out of the West segment, and I’m just wondering if we should think of that as a sustainable new run rate or is there any kind of one-time lower OpEx you may had there?

Allison Bridges

This is Allison Bridges. We have seen lower cost especially as a result of some of the reorganization that Don spoke about earlier and some of the allocated cost that we get.

Operator

And we will take our next question from Carl Kirst with BMO.

Carl Kirst - BMO

Just actually a few clarifications of things that were said prior, and maybe first starting on the Northeast on OVM. And Frank, I think you mentioned this but just to be clear that essentially the push out that we’ve seen and some of the milestones the Moundsville fractionator, et cetera that is all very deliberate with respect to matching up to industry activity right that’s got nothing to do with execution. Is that correct?

Don Chappel

I would say that the Moundsville frac train 3 is probably associated more with preserving that decision to be in line with the Bluegrass decision when we make that determination. I would say that moving the Moundsville frac train from 3 or 4Q of 2013 into 2Q of 2014 is a function of just physical execution of the projects that we’ve seen in that area.

Carl Kirst - BMO

Okay.

Alan Armstrong

So to be clear on that the demand is there for the first expansion or the Phase 2 Moundsville and is a matter of getting that project completed. The decision for laying down third is just because we think Bluegrass will reduce the need for local fractionation. And so we think that we are becoming more and more confident on the timing of Bluegrass such that we don’t need to have both the local frac and Bluegrass solution.

John Dearborn

Yes, definitely the second frac train at Moundsville, the 30,000 barrels a day definitely needed and as well as the stabilization plans and the deethanizers. And so those are all on track for completion in 2014 to support the drilling programs in place.

Carl Kirst - BMO

And then, Alan, just to kind of go back to Bluegrass and understanding the commercial sensitivity of where we are right now but I guess as you guys have opened the biddings the open season here, is the general approach a minimum take or pay type of commitments or is this something where for the right price you are willing to take volume risk?

Alan Armstrong

Yes, because that’s a regulated asset we offered out a I think very intelligent response to the market that allows us a considerably higher rate for people that are just wanting to dedicate acreage but not make volume commitments and then a very attractive rate to the degree people are willing to make a volume commitment, and there is various steps in between that. And so we’ve basically provided a menu for customers. And then we still once we get all that built into our analysis in terms of those options and we can decide whether that we think that degree of support justifies the investment in the project.

So it is a menu and it’s I guess had a very attractive rate, if you compare it to like an ATEX ethane where it’s a ship or pay kind of obligation on the one end and on the other end up to volume dedication with -- sorry, an acreage dedication at a much higher rate but one that gets that producer flexibility.

Carl Kirst - BMO

Okay. I appreciate the clarification. And then maybe just last question back on Geismar and the business in Russian insurance and I guess now that we have $50 million recorded degree to I guess by the insurance companies. And I guess the number is refined a little bit more from sort of the initial preliminary estimate. Don, do you feel more comfortable around the uncertainty range, if you will, around that number today versus say for instance on the second quarter call, meaning have there been deliberations with the insurance companies that have tightened perhaps the deviation of where that number can go to, or is it basically each time a new claim is filed it’s is a new claim and new process so to speak?

Don Chappel

No, I think we feel comfortable with our claim amount. Clearly, we have a good read of the policy and we certainly know the loss, the lost production, the actual amount that’s determined based on the market prices that we would have realized so that would be dependant on what happens on the market over the coming quarters. But certainly in terms of the volume the lost production we know that pretty darn well. So we think we got a sold basis for our estimate here.

I think the initial $50 million payment evidences good faith on the part of insurers they stepped up and paid us $50 million in advance of our actual claims because our out of pocket on the physical damage was not that substantial yet and we only had 13 days of covered loss under business interruption during the month of August. So they actually I think made a good faith early payment. So I think that’s a good sign.

Our next covered loss under business interruption would be for a partial month in October, so kind of the end of October, that’s when we assumed that the expanded plant will come back into service. So we’ll file a claim for the month of October during the month of November. And then we would expect that will take insurers a month or so to respond to us and we’re -- and that will be process every month.

So partial month on October filed in November give the insurers better time to review that claim and respond to it. And then we’ll have a full month loss in the month of November file that claim in December again the insurers a bit of time to respond to that.

So I think from a process stand point its pretty well established, I think volumetrically we know what their losses and we’re mitigating the losses to the best of our ability to economic losses, and then I think we’ll see where market prices turn out. But again we’ve outlined in our guidance what we expect the loss profits to be and the market price assumptions reviews there and that’s really what’s guiding this claim.

Operator

And next we’ll go to Bradley Olsen with Tudor Pickering.

Bradley Olsen - Tudor Pickering

We saw on the Leidy Southeast project most of the shippers on that project were downstream or LVC. Are you seeing more upstream demand as you’ve gone out with the open season on Atlantic Sunrise?

Rory Miller

Yes, Alan, would you like me to take that.

Alan Armstrong

Please, Rory, thank you.

Rory Miller

Yes, Bradley, this is Rory Miller. It has been changing and there was an earlier question about pricing in the northeast. Of course we’re looking through at a knot hole a bit there but certainly what we’ve seen on our current Leidy system that moves about 3 Bcf a day. There is much more gas that that trying to get into that line every day. We’ve got 8 Bcf a day of interconnections there. And so there is a lot of gas on gas competition for things that are playing the spot market and the prices have been huge discounts to the Henry Hub.

So I think that really is leading up to answer your question and that’s that we have seen a lot stronger response from the producer community. That being said, the people that made requests within the open season were fairly balanced between the market side and the supply side. But the producers were definitely stepping up in a much bigger way than what we’ve historically seen on Transco.

Bradley Olsen - Tudor Pickering

And you alluded earlier to having interest from potential partners in the Bluegrass project and in the past with projects like Constitution, you’ve obviously brought E&P partners into the project to secure volumes. Have you found so far that there are E&P shippers who are may be making their participation in Bluegrass contingent on getting a significant equity stake in the project?

Alan Armstrong

No, we really haven’t seen that from the key customers that we’re talking to because it’s such a big investment. Mostly, usually when we have parties that are wanting to take equity it’s a project that’s fairly specific to their needs. So for instance, Constitution with Cabot that project was mostly capacity mostly taking by Cabot and they wanted to make they were involved and had a stake in making sure the project was executed well and as well enjoyed some of economic benefits of their capacity obligation.

I think in Bluegrass we’ve got a variety of different shippers such that its not -- not enough, nobody has a dominant position the pipeline like we seen on some of those other assets. Having said that, I would tell you there is a lot of entrance from more strategic players I would say in wanting to have an interest but its not likely going to be, from the E&P side for reason we stated.

Bradley Olsen - Tudor Pickering

And then the MOU that you alluded to last year when you acquire the ACMP interest that Chesapeake would at least intended to commit volumes, is that still an agreement that’s in place as it pertains the Bluegrass?

Alan Armstrong

Yes.

Bradley Olsen - Tudor Pickering

And then just jumping to the Canadian side, just in rough numbers maybe when you think about the top line in the Canadian off-gas processing business, how much of the revenues there, and I realize its kind of a key pole arrangement in the off-gas processing, but what percentage of that margin is coming from the olefin side versus from just the NGO side?

Alan Armstrong

We’ll have to get back to you on that. That mix has moved a little bit just recently as now we’re starting up the ethane recovery plant and that business is I’ll remind you is a floor heavy margin on it that has a floor that we’re operating at because ethane is -- it's based of off Belvieu ethane and, therefore, that will be a 60 that will not be commodity sensitive. But we can get back to you some detail, I don’t have that right up top of my head here.

John Dearborn

And this is John. I don’t have the precise number but the majority would be NGLs and the minority being olefins out in Canada today.

Bradley Olsen - Tudor Pickering

And just one final one, looking through the guidance and there are couple of other questions that alluded to this point. In the Western segment, you mentioned some of things in a field that you were doing more efficiently and certainly I looked is though there is a big move up in 2013 full year EBITDA guidance and fairly sizable move in 2014 and then a little bit smaller move revising upwards in 2015. May be just qualitatively, if you could, talk about why is it that the benefit from those off cutting or efficiency gain initiatives that you’re taking gave a larger -- provide you with a larger step up in guidance in 2013 and 2014 than it did in 2015?

Alan Armstrong

Well, I think what you’re really seeing there is just a lack of confidence and drilling volumes continuing out west it’s really what’s driving most of that. And so the cost savings I think are very apparent to us there, but I would just say I think most of that’s driven by an expected decline in volumes out west.

Operator

And we’ll go next to Curt Launer with Deutsche Bank.

Curt Launer - Deutsche Bank

Two questions if I may, one more back to the Marcellus. In the 10-Q you’re referring to most favorable economics in the western region and I think that’s been discussed a lot already in this call. But from the standpoint of the lower volumes in 2013, what are the conditions, what are you seeing relative to your discussions with producers that could make that materially better in 2014 and 2015, clearly we think about it from the standpoint of NGO takeaway capacity boosting the netbacks or is it a question of natural gas prices needing to be higher that would spur that activity?

Frank Billings

Yes, this is Frank. I'm assuming you’re referring to the western part of the Marcellus --

Curt Launer - Deutsche Bank

That’s correct.

Frank Billings

Our eastern business up there? I would say that the biggest thing we see relative to the western area and volumes is more a function of what’s the ultimate netback might be for those areas especially if you get into Northwest Pennsylvania Northeast Ohio some of those areas that are very infrastructure challenged. I think in the -- in our area especially or in the OVM area, I think we have -- we saw an improvement in the netbacks when we brought our fractionation train on and we’re going to see continue to improve the netbacks to the producers when we bring on this stabilization plan and the next fracturing as well as railroad facility.

So for us in OVM I think it’s going to be able to show a consistent ability to get the commodity sold into the market, and I think that’s what’s going to support in our area we’re currently operating, but I do think the western part of the Marcellus is going to see and even Ohio just going to see -- we’ll see some of -- could see some of the same pinching of basis relative to Natgas sales and NGL prices and supplies outstrip being able to get those commodities out of there.

Curt Launer - Deutsche Bank

Switching gears to the Canadian assets so I wanted to ask if there is anything else you could tell us that will help us model that into the outlook here you mentioned the PIK units certainly, but what would be the expectation relative to debt as being part of the financing package as the assets are dropped down?

Don Chappel

Curt, this is Don. Again I think as Alan mentioned, we expect the multiple not to exceed seven times and the purchase price. We expect it to be all equity. That then pages from the tax standpoint to Williams. Again we defer taxes on that basis other than this tax that’s triggered by changing the older strip structure of the Canadian assets to WPZ. So that’s really the driver there that responds to your question.

Operator

And we’ll go next to Becca Followill with U.S. Capital Advisors.

Becca Followill - U.S. Capital Advisors

Could you clarify in the northeast -- I'm sorry to keep harping on it, but I think you talked in the other slides your deferring $200 million a day of processing out of 2015 until latter period and 30,000 barrels a day frac, yet we don’t see CapEx go beyond, can you reconcile that?

Don Chappel

Yes, I think what we’ve done is we need the -- we need the second frac train. If you look at our 2014 volumes -- 2015 volumes in OVM, we will need to start to put the second 200 million a day train at Oak Grove again, but a lot of that balance of plan work has been done as part of the initial work. So we don’t have a significant requirement but we have pushed that out to where we might not be -- we may not have to spend those dollars until 2016 given the current volume forecast that we have today. So we have that’s probably the only asset that we kind of shoved out of the 2015 into 2016 relative to kind of the assets that you’ve seen before.

Becca Followill - U.S. Capital Advisors

I think the frac capacity is down by 30,000 barrels a day also.

Don Chappel

That’s the other one yes I mentioned earlier.

Becca Followill - U.S. Capital Advisors

So, are you saying that the CapEx you’ve already spent the dollars on that and so that probably we don’t see CapEx coming down?

Don Chappel

Well, we have purchased that frac train, so we have that in our inventory. We’re looking to redeploy that in the either some of our other opportunities that we have going on today whether it would be up to 3RM. But today most of the CapEx to get the kind of the investments that you see as on the slide, Slide 8 most all that capital will be deployed in 2014 and we have a little bit of capital in 2015 that prepared to get the second Oak Grove facility on. That one would be in our 2015 plan but beyond that we pushed out processing plants three and four and some of the other things that we've had in our 2015 plant.

Becca Followill - U.S. Capital Advisors

And then this is smaller in the scheme of things but I don't have all the numbers in front of, looking at the maintenance CapEx, in this guidance it’s down by $85 million over the three year period and it looks like the last -- probably the last four quarters maintenance CapEx keeps coming down and an aggregated material relative to the size of the maintenance CapEx. Can you talk about what is diving that and your thoughts behind the maintenance CapEx?

Alan Armstrong

Sure. As I mentioned earlier, you we’re still spending that a very large amount of our profit particularly within the pipes impact over 35% of our segment profit we’re putting back in the maintenance CapEx, if you take the three year maintenance CapEx and put that over the our segment profit. And so, very significant amount still going into that. But I would say that we invested very heavily in both the 2011 and 2012 in catching up and beating a deadline that we had relative to some regulatory requirements or getting some of the asset integrity work done on the pipeline. So we had kind of a lot of the Capital squeezed into 2011 and 2012 period.

And as well, we also had things like we had some work that we had to get done to the Clean Air Act on so on our compression on our major pipelines that we had to get done as well. And so again those kind of culminated in 2011 and 2012. And so we’ve been working that hard in terms of getting done what we needed to get done for those timeframes, but it’s allowed us a little bit of relaxation here in terms of that heavy capital spending in the guidance currently that we have before us.

Becca Followill - U.S. Capital Advisors

I understand why it was higher at 2011 and 2012, but what I don’t understand is why the guidance keeps coming down for 2013 through 2015, because it might have passed, so why would the guidance keep down (inaudible)?

Alan Armstrong

I'm sorry, I didn’t follow your question there. Well, couple of things. One, with the continued decline in volumes in the west we have less maintenance CapEx and we’ve made some decisions, as I mentioned earlier, for doing things like taking the Lybrook plant out of service. So some of our older fleets out west is a result for the volume reduction and those older plants as you can imagine suck up maintenance capital. And so those changes have been made to our midstream maintenance CapEx.

And on the gas pipes, one thing we did do and I'm not sure this is a major driver but its certainly embedded in here is we had some pressure testing obligations that we were trying to get all done by 2018. We took a really close look at those in terms of really where we needed to reduce risk on the system and negotiated with FEMSA to and got them to understand that really the better risk reduction was spreading out that timeframe on some of that pipeline integrity work. So that spread things out a little more versus where we had some dollar spending in there in 2018. So that’s a little bit of that reduction on gas pipes, but I think the major reduction you see is really on the midstream side and it really is the teams out west are working pretty hard to reduce our maintenance capital out west that's a result of producing volume.

Rory Miller

Hey Alan.

Alan Armstrong

Yes.

Rory Miller

One other item too is probably worth mentioning to Becca here. With the changing flow patterns on the Transco system where we’re now getting a lot of our supply or much of our supply from the northeast as oppose to just the Gulf Coast, the middle portion of our system is the compression on our portion of our system is running much less frequently. So we’re having a lot less hours on those units we’re having a lot less maintenance there and our turbine change outs are been able to be pushed out in the future year. So as we kind of put that that whole new dynamic into the equation that also been a significant impact.

Alan Armstrong

Great point, thanks Rory.

Allison Bridges

Yes, and this is Allison Bridges. And I would also just like to add to the lower sort of maintaining the facility as we do have some pretty significant reduction in well connect than we had previously had. So, at least through the next few years that’s continuing to come down.

Operator

We’ll go next to Selman Akyol with Stifel.

Selman Akyol - Stifel

In terms of the Canadian assets, in your assumption there for the $200 million what capacity utilization have you guys assumed?

John Dearborn

That’s sizable -- there is actually three assets there to be thinking about. One is the liquid extraction plant up in Fort McMurray, the other is a pipeline and the other is the fractionator. And in terms of our operating in the next year in the future years, the fractionators is going to be running near to full capacity. It will need some incremental expansion in order to accommodate the CNRL plant. And the liquid extraction plant up in Fort McMurray when the upgrade was running was full we’re running pretty much full out because it’s dedicated to that facility.

Unidentified Company Speaker

Ethane recovery.

John Dearborn

I’m sorry?

Unidentified Company Speaker

Ethane recovery.

Alan Armstrong

I would also add is that normally built into that about a 97.5% run time. So in terms of how much that’s up and that’s consistent with our typical capabilities.

Unidentified Company Speaker

And perhaps expected at the pipeline.

John Dearborn

Yes, the pipeline will have a little bit of excess capacity as we will have some room on it as we bring on these other projects into the future.

Selman Akyol - Stifel

And then just to confirm still looking for an April 1 start on Geismar?

Alan Armstrong

Yes, that is correct.

Operator

That concludes today’s question-and-answer session. Mr. Armstrong, at this time, I would like to turn the conference back over to you for any additional or closing remarks.

Alan Armstrong

Great. Well, thank you very much for joining us today. We are blessed to have such a great portfolio of both major growth projects to pursue and those keep coming on. And that gives this confidence in our ability to continue to grow our WMB dividend and in our distributable cash flow at WPZ for many years to come. And we certainly are excited to make the step we're making on the Canadian asset dropdown which moves us closer to a pure play, but we also retained the benefit of some very significant dropdown candidates for WPZ in the future. So we think structurally we are very well positioned, and we think in terms of our business opportunities they just couldn’t be more robust. And the team is very excited about continuing to execute and deliver on this tremendous cash flow growth. So thank you very much for joining us this morning and for the great questions.

Operator

Thank you. This does conclude today’s conference. We appreciate your participation.

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