Keyera Corp.

John Cobb - VP, IR and Information Technology Jim Bertram - Chief Executive Officer David Smith - President and COO Steven Kroeker - Vice President and CFO

David Noseworthy - CIBC Matthew Akman - Scotiabank Robert Catellier - Macquarie Steven Paget - FirstEnergy Capital Rob Hope - TD Securities

Thank you, Steve and good morning. It’s my pleasure to welcome you to Keyera’s 2013 third quarter results conference call.

With me are Jim Bertram, Chief Executive Officer; David Smith, President and Chief Operating Officer; and Steven Kroeker, Vice President and Chief Financial Officer. In a moment, Jim and David will discuss the business and Steven will provide additional information on our financial results.

At the conclusion of the formal remarks, we’ll open the call for questions. Before we begin, however, I would like to remind listeners that some of the comments and answers that we will be providing today speak to future events.

These forward-looking statements are given as of today’s date and reflect events or outcomes that management currently expects to occur based on their belief about the relevant material factors as well as our understanding of the business and the environment in which we operate. Because forward-looking statements address future events and conditions, they necessarily involve risks and uncertainties that could cause actual results to differ materially.

Some of these risks and uncertainties include fluctuations in supply, demand and pricing of natural gas, NGLs, isooctane and crude oil, the activities of producers and other industry players, our operating and other costs, the availability and cost of materials, equipment, labor and other services for capital projects, governmental and regulatory actions or delays, and other risks as are more fully set out in our publicly filed disclosure documents available on SEDAR and on our website. We encourage you to review the MD&A which can be found in our 2013 third quarter report and our annual information form, both of which are available on our website and on SEDAR.

With that, I’ll turn it over to Jim Bertram, Chief Executive Officer. Go ahead, Jim.

Thanks, John, and good morning, everyone. Thank you for joining us this morning.

The demand for Keyera services and products resulted in continued strong financial performance in third quarter of this year. This demand comes from two primary sectors that drive our business; the development of liquids rich natural gas on the west side of Alberta and the growth of the oil sand sector more specifically the growing demand for condensate services.

Increasingly producers are looking to companies like Keyera to assist them in their development plans by constructing the surface infrastructure necessary to turn their production into cash flow. This is particularly true in West Central and deep basin areas of Alberta where producers remain focused on liquids rich resource type drilling, as a result we have recently completed or are in the process of negotiating to build several new pipelines and plant facility.

In the third quarter we received regulatory approval for the Wapiti pipeline system clearing the way for construction this winter of the 90 kilometer 12-inch raw sour gas gathering pipeline and a six inch segregated condensate pipeline. When these pipelines are operational which we anticipate to be in the second quarter of 2014 they will provide processing options for raw, sour gas and condensate into Wapiti region of Alberta at Simonette gas plant.

The Wapiti area is the highly perspective region where producers are targeting multiple geological horizons the best one which is the liquids rich Montney, producers in the area are showing tremendous interest in the remaining capacity on the system. In order to handle the volume of raw gas we anticipate Simonette, we also intend to expand the plant by adding condensate stabilization as well as additional refrigeration which will add 100 million cubic feet per day of raw gas processing capacity.

Our goal is to split these plant modifications in the second half of 2014. We are seeing increases in throughput at several gas plants including Caribou and BC Strachan and Minnehik Buck Lake plant through new pipelines put in the servers in 2013.

We currently have four other new gathering pipeline initiatives in various stages of development, three of them feeding the Rimbey gas plant. Rimbey is situated in a sweet spot for liquids rich gas production supporting production from number of liquids rich zones including the Glauconite and the southern Duvernay geological horizons.

We are working on a project to the bottlenecks that the Carlos pipeline it is beginning to approach capacity. By constructing the short connector pipeline from Carlos to the other existing Keyera pipeline infrastructure in the area, we would be able to offload volume from Carlos for delivery to Rimbey initially and to Keyera plant in the future.

We anticipate completing this project in the second quarter of next year. Also Rimbey we will be purchasing the short gathering pipeline that’s been built by a producer which will allow us to increase throughput.

To the west of the plants we are currently working at the producer to develop a first phase of Wilson Creek pipeline system. This project involves a 30 kilometer pipeline system consisting of a 12 inch raw gas gathering pipeline and a 6 inch pipeline dedicated to condensate.

This project is subject to both parties signing definitive agreements and could be completed by mid 2014. We're also working with producers interested in the pipeline to deliver gas to our Brazeau River and West Pembina gas plants.

This project, which we are calling Twin Rivers pipeline would be a 12 inch, 38 kilometer gas gathering pipeline. Assuming timely completion, definitive agreements, construction could begin shortly and the project could be completed as early as the second quarter of 2014.

These pipeline projects demonstrate the considerable activity underway in many of the areas around Kereya plants and the value that Kereya is providing to its customers. In September, we successfully completed maintenance turnaround at the Simonette gas plant, this was the last of our scheduled maintenance turnarounds for 2013.

With that, I'd like to turn it over to David to review our liquids business unit. David?

Thanks Jim. The Liquids Business also posted strong results in the third quarter, with contribution from both the NGL Infrastructure and Marketing segments.

The combination of liquids-rich drilling in Western Canada and oil sands developments has resulted in excited times for our NGL Infrastructure business. Demand for fractionation and storage services at Fort Saskatchewan continues to grow, with the higher fractionation and storage fees we have seen this year, it’s part of our business was a strong contributor again in the third quarter.

In August, we received regulatory approval for our de-ethanizer project at our facility and Fort Saskatchewan, another example of the growing variety of services we are providing to produces of liquids rich natural gas in Western Canada. Site preparation is well underway and facility scales are being completed.

That will allow us to start construction on-site shortly. We are also pleased with the interest shown by producers and an expansion of our C3+ fractionator at Fort Saskatchewan.

We're currently evaluating the results from our frontend engineering and design work in order to better define construction costs and schedule. From there we expect to finalize commercial terms and sign binding agreements with our customers.

Demand for storage services continues to grow, particularly for condensate. In July Keyera’s 12 storage cavern received regulatory approval and was put into service.

The silver work for the new brine pond to support our cavern development was completed earlier this year and installation of the pond liner is nearly complete. Pumps will be installed prior to putting the brine pond into operation in the spring of 2014.

Washing of the 13th cavern is continuing and we're preparing to drill the wellbore for the 14th cavern at the site. We're also continuing to work with producers to develop the Alberta liquids pipeline system as a transportation alternative for NGL mix and condensate from the Deep Basin area of Alberta to Fort Saskatchewan.

At Alberta EnviroFuels an unscheduled outage resulted in the facility being offline from mid June to mid July. The combination of lower production during this period and the associated cost of the repairs affected the financial results in the NGL infrastructure segment in the third quarter.

In addition the catalyst changed out in September contributes to higher than expected third quarter maintenance capital costs. Keyera will be taking Alberta EnviroFuels offline in the fourth quarter to address certain issues currently limiting the plant’s production capability.

Assuming more goes as planned, we anticipate at the facility will be offline for approximately 30 days. Demand for the oil sands services we provide is driving a lot of growth in our NGL infrastructure segment.

I am pleased to announce that construction of South Cheecham Rail and Truck Terminal was completed in the third quarter and the facility was commissioned in September. The facility is now receiving and loading bitumen onto railcars for delivery to end-use markets.

We anticipate usage of the terminal will ramp up over the next few months. And we continue to discuss with customers the potential for expansion of the facility.

In July, we announced the partnership of Kinder Morgan to construct the Alberta crude terminal, our crude oil loading facility located next to our Alberta Diluent terminal in East Edmonton, Alberta’s crude oil hub. Since that time, we have made good progress clearing the land and preparing the site, when the first phase is complete, the Alberta crude terminal will be able to load approximately 40,000 barrels per day of crude oil for delivery to customers across North America.

With a connection to Kinder Morgan’s crude oil storage facility in Edmonton, and access to both the Canadian National and Canadian Pacific main lines, the terminal will provide tremendous flexibility, allowing customers to secure many different crude plants and the ability to direct the product by rail anywhere in North America. Subject to regulatory approvals construction of the facility will begin shortly.

And we anticipate being able to more railcar volumes in the second quarter of 2014. We are currently in discussions with customers about a possible expansion at that side as well.

Last week Enbridge announced the barrel proceeding with development of the Norlite pipeline, a diluent transportation pipeline that will run from Fort to Saskatchewan to the Athabasca oil sands region near Fort McMurray. Keyera has the right to participate in the pipeline as a 30% non-operating owner and we expect to make a decision shortly.

As part of the Norlite service offering the Norlite shippers may access certain existing capacity on the Keyera pipeline in the Edmonton, Fort Saskatchewan area we anticipate that the shippers on the Norlite system will also be interested in accessing other condensate services we are able to provide in the Edmonton, Forts Saskatchewan area such as storage and rail terminals. In the marketing segment higher iso-octane sales emergence contributed to strong results in the quarter.

Butane prices continued to be relatively soft in the third quarter because butane is the feedstock used in the production of iso-octane we have been taking advantage of opportunities to purchase and store greater amount of butane to manage the supply requirements for Alberta EnviroFuels. Propane markets in North America were difficult for the third quarter Keyera continues to build inventory levels in the third quarter in order to meet winter sales commitments.

In order to protect the value of this inventory we have entered into propane physical and financial forward sales contracts. Condensate demand and pricing continued to be weak throughout the third quarter in Canada, this was largely result of a continued over supply of diluent in Alberta caused by slower than expected ramp-up in bitumen production as a result margins and volumes imported into Alberta were weak during the quarter.

With that I will turn it over to Steven to discuss the financial results in more detail.

Thank you David. As Jim and David mentioned we are pleased with our financial results for the third quarter EBITDA was $82.6 million 36% higher than the $60.8 million recorded in the third quarter last year this increase was primarily due to the strong performance of all aspects of our business relative to the third quarter of last year.

Net earnings were $40.8 million or $0.52 per share compared to $14.2 million or $0.18 per share in the third quarter of 2012. Higher operating margin from our business segments this quarter as well as lower noncash charges where the region for the increase in earnings, distributable cash flow of $50.5 million or $0.64 per share compared to $18.8 million or $0.24 per share in the third quarter of 2012.

Dividends for shareholders were $45.5 million or $0.58 per share resulting in a payout ratio of 90% for the quarter. The higher than usual payout ratio is primarily the result of higher maintenance capital expenditures and higher long term incentive plan expense.

On a year-to-date basis our payout ratio is 61%. Our gathering and process business posted strong operational results in the third quarter delivering operating margin of $40.7 million, $5.1 million higher than the same period last year.

As was mentioned earlier we saw higher throughput at our Caribou, Minnehik Buck Lake and Strachan gas plants this quarter. In the liquids business unit NGL infrastructure segment delivered third quarter operating margin of $31.4 million a new record compared to $29.9 million in the same period of last year.

Despite the cost associated with the outage area. The marketing business generated $33.2 million of operating margin in the third quarter significantly higher than the $16.7 million recorded in the third quarter last year.

All products within the segment performed pretty well as David previously mentioned. Included in marketing operating margins for the third quarter was approximately $25 million of realized losses.

Approximately $16 million of that related to risk management contracts put in place to lock in the surprise price of butane and to protect the value of products held on inventory. A portion of these losses related to butane that remain inventory at the end of the quarter and yet to be sold or consumed at feedstock Alberta EnviroFuels this creates a mismatch between accounting periods and Keyera expects to see higher margins in future periods when the inventory is sold or consumed.

Keyera’s general and administrative expenses were $6.1 million in the third quarter of this year compared to $5.2 million in the third quarter of 2012. This increase is primarily due to higher staffing and related costs to support Kereya's growing business.

Long-term incentive plan costs were $7.1 million in the third quarter compared to $5.5 million in the third quarter of last year. The higher expense is primarily due to the strong performance of Keyera’s business and the growth in Kereya's share price.

Finance costs were $12.3 million in the third quarter, slightly lower than the third quarter last year. Keyera incurred about $900,000 of cash taxes in the third quarter, about the same is in the third quarter of 2012.

These taxes primarily related to one of Keyera’s subsidiaries. In 2014 Keyera estimates that its cash taxes will increase to be between 8% and 12% of distributable cash flow.

This forecast is based on Kereya's estimates of future cash flow, and the timing of future growth projects and are subject to change. The value of inventory at the end of the third quarter was $253 million, $35 million higher than at the end of the second quarter and $57 million higher than at the end of the third quarter last year.

This increase is largely the result of maintaining higher levels of butane inventory in 2013 to support the isooctane business, as well as the higher product values. At the end of the third quarter Keyera had a $290 million drawn on a $750 million bank credit facility compared to $135 million drawn at year end 2012.

Keyera’s ratio of debt to EBITDA a primary covenant for Keyera’s long-term debt was 1.84 times at the end of the third quarter. This metric reflects the fact we are permitted to deduct working capital surplus in calculating debt.

In September we announced $506 million of additional private placement debt financing approximately $200 million closed in October and the remainder is expected to close in November of 2013 and April 2014. The proceeds received in October were used to pay down our bank credit facility the remaining proceeds will be used to further pay down the credit facility and to help fund our growth capital program.

Keyera continues to execute on over $900 million in approved projects. However changes in the construction schedules to several large projects means that we now anticipate that our growth capital investments in 2013 will be between $325 million and $375 million and for 2014 will be between $500 and $600 million.

Finally we've included our third quarter supplementary information on our website concurrent with the release of our 2013 third quarter financial results. This information includes both operating and financial data for each segment of our business you can refer to our 2013 third quarter report the details on how to access the supplementary data.

Jim that concludes my remarks.

Thanks, Steven. I’d like to conclude with a few comments about the opportunities I see ahead for Keyera.

Over last several weeks we've spent a considerable amount of time reviewing each segment of our business in order to develop our budget for 2014. Beginning with the macro assessment of the factors driving our business we've looked into detail of our existing source of cash flow and assess the potential to deploy new capital in order to grow in the future.

I am pleased to report that we see continued demand for our services in both our business units and numerous growth opportunities available to us. We're very proud of our achievements at Keyera and the culture that we've developed here, which emphasizes customer service team work and the commitment to our core values.

We've asked a lot of our employees over the past year, it will be expected a lot more from them in the future, I often say that our greatest asset is our people and I want to recognize our contribution to our success at Keyera. In particular, I would like acknowledge the contribution of a key member of our executive team, Marzio Isotti was has announced his intention to retire at year-end.

Marzio joined Keyera in 2000 and rose to be Senior Vice President of gathering in processing. Marzio was very instrumental in developing Keyera’s gathering and processing strategy over the last decade, was a significant contributor to growth of that business.

While we have a robust organization that is able to continue its work in this area, we’ll certainly miss Marzio’s wisdom, insight and friendship. Behalf all of the Keyera, I wish him health and happiness as begins any stage of his life.

John, that concludes my comments.

Thanks Jim please go ahead Steve.

Thank you. Good morning gentlemen.

Good morning.

As far as we did take a moment to better understand the realized hedge losses in the quarter, in your MD&A, you just said in the prepared remarks, the portion of the realized losses for the department and inventories that is yet to be sold or consumed, can you provide us any additional color regarding what percentage of that $16 million in butane realized such as relates the volume still inventory?

David, it’s John, I will answer that question. It’s difficult to quantify the exact number and so I am not sure that we can give you an answer in terms of the quantitative answer in terms of the higher margins that we expect to see in the future.

But just to elaborate briefly on that, these are hedges, these are butane hedges that settled in the third quarter and as a result of increasing prices they’ve settled realizing a loss in the period. The offset to that would have been again that would have come from the physical side of the business whereby we would in a normal quarter perhaps removed butane from inventory and sold it either into the market or sold it to the Alberta EnviroFuels facility for consumption in the production of iso-octane.

Because of some of the operational problems that we saw at AEF, we did not see as much butane come out of inventory and generate the offsetting gain that you would expect to see with an effective hedge program. And so the challenge for us becomes one of trying to time and understand when that will come out with the outage that we are taking at AEF in December that will make way for some of those higher margins into the first quarter.

Okay. So I guess so maybe I will start off with so the timing is because we are having 30 day outage at AEF I might not see all that recovery that I might have gotten in Q4 about and some in Q1, but I won’t see any in Q2?

Well, I don’t know I can’t say that of course because I can’t predict with any degree of accuracy the timing that that will occur, but notionally we saw some of that in October, the benefit of that inventory and we expect to see it in the future, it’s sitting there as if you want to think of it as low cost inventory. And when it’s delivered to the market and sold and though that sales reflected in our financial results, we’d anticipate in the margin then.

And then in terms of, I know it’s hard to give a precise number, but in terms of is it more than half of the $16 million less than half, can you give any kind of color or is that still difficult well?

Well yeah, it is not something that I think we are able to provide. What I would say is intuitively if you have an effective hedge you’d expect that if it behaves in that manner that you’d see an offset where you have a realized gain or loss on the financial side, you would expect to see the offset on the physical side.

In terms of, do we see anything similar for the propane in the sense you are also building propane inventories, but would we have seen any kind of realized loss on propane hedges in the quarter that might be recognized in terms of fiscal sales is in Q4 and Q1?

David, it’s David Smith, I will answer that one. We have seen over the course of last two quarters a fairly typical build up in propane inventory in terms of physical volume.

But as you can appreciate the hedging strategy that we've had for the last couple of years is basically physical or financial forward propane sales contracts. So it's a direct and fairly effective hedge.

And so that one of the benefits of that is that you don't see the same variability in the propane results as perhaps you have seen in past years. And so, I would say no that you’re not seeing the same kind of issue with a mismatch in the physical versus financial on the propane side.

And no concerns about timing mismatch either?

No, in the case of propane we have, I think it's fair to say, we have more, we have greater confidence in the timing of the sales. And therefore our hedges tend to be matched in terms of the timing of the volume movements, I think it's probably fair to say, it's a better match than it is for the butane that John was talking about.

Okay. Appreciate that color.

And then in terms of the AEF turnaround in Q4, is there any estimate in terms of cost or operating margin impact?

No, the short answer is no in fact it's a bit preliminary for us to be able to try and provide any kind of a quantitative impact. I don't imagine it will be at the end of the day much different than what you saw in the June and July outage.

I guess the difference is we've had a little bit more time to plan this particular outage. And we're fairly confident in terms of what the timeframe will be subject to obviously the kinds of unexpected issues that you might come across.

Thanks. And then one last question in terms of the development of a new fractionator you mentioned that you’re going to exceed work now and then looking to do some finalization of binding agreements with producers.

Do you have any kind of a rough timeline for when you might get to that binding agreement stage?

I would say it’s my best estimate right now it’s just a matter of a couple of months whether it’s before year-end or after year-end I think that’s certainly our target right now. It’s a little difficult to predict though because we still have discussions with a number of producers to conclude.

Perfect. Thank you very much.

I really appreciate your time and answers.

Thank you very much. I guess what we're seeing here a little bit for the first time is the operating risk at AEF as it relates to marketing and a lot of money has been made there on the other hand, so obviously it’s positive.

But David I am just wondering whether the risk that you now are experiencing there is coming to [fruition] makes you a little more cautious about holding so much butane and inventory and maybe keeping that a little bit more skinny just in case there is an operating issue at the facility because if you hold all this butane inventory, as John said, you should be able to capitalize into the market, but if butane prices move against you maybe not so is that a risk that an emerging risk I guess that you’re trying to address?

It’s a fair question Matthew, but I think the short answer is I don’t see a whole lot of reason to adjust our strategy with respect to butane purchases and the amount that we hold in inventory. There is a variety of reasons for the strategy that we've adopted.

One is just to manage the operational, the fluctuations in volume requirements, which arise as a result of both operational issues, as well as some of the variations in demand within the market. Keep in mind too that there is lots of other uses for butane, being able to sell the butane into the market in Alberta is not huge challenge for us, we have lots of other markets, lots of customers as well.

And so taking advantage of some of the seasonal opportunities that we see in butane and keeping the flexibility to be able to manage some of the fluctuations at AEF I think and I would say too that the volume of butane that we have in inventory doesn’t really represent all that many days of production. So for all those reasons I think we would intent to stick with the same strategy.

Okay. Thank you.

I would also add that the whole purpose of the hedging the butane inventory when it first comes in that you hedged in and locked in the supply cost of that butane, so you are not really too worried about the movement of fluctuations of butane prices going forward after that.

Okay. Thank you.

On Norlite, what is really driving the decision as to why do you participate and exercise the option, is it the other opportunities that might emerge for Keyera or I mean what plays into that because the returns are I guess at least the base returns now are fully largely known?

Yeah. I think the base returns are certainly known, I think what we are trying to do right now is evaluate some of those additional opportunities as you mentioned Matthew.

The announcement, -- announcement was just only last week and so we are just taking a prudent amount of time to make sure we understand the details of the contractual arrangements, the commercial terms and having a review, a more detailed review of the economics before we make our final decision.

Okay, thanks guys. Those were my questions.

Thanks. Jim I wondered if you could spend a minute giving an update on what you are seeing in terms of producer activity, strategies in the Duvernay, in particular two points of interest here.

I wondered if you could just sort of book in what type of growth rate we could expect to see through your existing plants over the next few years should the current trends continue? And then secondly, producers’ attitude towards partnering with midstream companies versus building their own infrastructure for the Duvernay?

Hi Robert. Well, I think for Duvernay it’s important to kind of differentiate two areas I think I’d call that the Northern Duvernay the area around [CARBOB], Simonette and it appears to be the most perspective today the one that’s getting maybe 70 days into their attention.

I think there, Duvernay could be sort of summarized at very perspective and there is a lot of exciting things have been announced I think with the majors all playing in there, Shell, Chevron, Imperial. And I think the issue there it’s a very bottlenecked part of the world.

And so we are going fast, at Simonette others are going fast on pipe and egress. But the reality of it is nothing is going to happen quickly.

And it’s going to evolve as the infrastructure evolves. So I suspect as much as enthusiasm there is for the Duvernay there that this is going to continue to be bottlenecks.

And how it evolves, I think we will have lots of opportunities to grow our Simonette plant and pipeline systems, but it’s going to go slower because it takes time. I think the Southern Duvernay which I would characterize as the areas around Pembina, Williston Green in our Rimbey area sort of surrounded by striking and many -- We will probably have eight or nine facilities that can access that Duvernay liquids trend in that area.

I think talking to producers they like it, they like the rocks, but it’s probably going slower, they haven’t maybe, a couple of producers haven’t quite cracked the nut, but I think they haven’t spent as much money there and I think you’re maybe seeing 20% of the activity levels in that area, I think this is just more in Talisman had a, or yesterday Talisman had released and talking about a couple of Duvernay wells. So I think we certainly encourage producers to focus more on the South if they have choices because we have infrastructure that kind of accommodate them immediately and get their liquids-rich products to market through pipeline systems and get them almost Edmonton type pricing for condensate and NGL.

So we're certainly try to influence that, but obviously it comes down to geology and rocks. And I just get a sense that the Duvernay is starting to pick-up a lot of momentum.

But for now I'd say a lot of the focus has been up in the Northern area. So the rocks favor the North, but the infrastructure doesn't and infrastructure favors the South and I think it's just going to go a little slower.

When you see that they’re ramping up and producers start putting together long-term capital budgets for, let's just focus on the Northern Duvernay. What type of pull-through affect do you think it's going to have on volumes?

It sounds to me like it's more of a greenfield opportunity in addition to what's around Simonette. But again, can you address the current thinking in the producing community whether or not they're more inclined to partner versus build their own processing plants?

Well, it's tough, they are all going to have different views on it. But I think we certainly have seen a number of producers very interested in what we can provide in terms of processing capacity and the ability to move their products out there.

So mostly a condensate play, condensate stabilization and getting condensate barrels to market seems to be a key focus for them because the pricing for condensate. I think eventually everybody wants to get all of that heat out of their gas stream, but I get a sense that condensate is going to be front center for the next few years because of the value proposition there.

I think it’s too early to say exactly how it’s going to evolve. I was going to speculate, I’d say it’s going to -- there are going to be a lot of midstream opportunities for us and others and some producers will continue to use other thing.

What I would stress is I think in that area the Duvernay and Montney is going to turn out to be a big opportunity to grow infrastructure for a lot of people and I think we're still very early days on the Duvernay play up there, very early days and that’s even very early days for the Montney in the (inaudible) area. So it’s going to take a little bit of time.

Okay. It’s a fair answer and thanks for the color there.

My next question I guess is for David just in terms of the fractionator, should you be successful and commercially securing that project? Is there going to be any other additional assets required and I am thinking of course of pipelines and storage or are these and some supporting assets already included in your CapEx plans or otherwise available in the market?

Well, I think as we finalize the cost estimates, Rob, first of all we will certainly be including all of the costs associated with the projects. There are certain pipeline connections and then pumping facilities to enhance flow rates and things like that that will be part of the project.

At this stage it’s not clear whether there is any implications with respect to storage, but I am hoping not. We are taking one cavern with let’s say the ethanizer next year, we will be taking one cavern and turning it into C2+ storage because we need our cavern to be able to provide the feedstock for the de-ethanizer.

So we’ll have one cavern in C2+ mix and hopefully just one cavern in C3+ mix as well. And so that will allow us to continue as we develop additional caverns on the side that will allow us to provide those in commercial service for product like condensate.

But there will be a fair bit of other sort of related infrastructure with respect to pipeline connections and that sort of thing and that's all part of our cost equation as we go through the final stages here.

Okay. You answered my question.

Thanks.

You’ve had some success adding value to butane with the AEF, is it possible Keyera could build or buy a plant that would add value to propane in western Canada?

It’s certainly possible, Steven. We have as the growth in propane supply through North America has grown and we've seen prices, relative prices for propane decline over the last couple of years.

We certainly had many conversations about what that might mean for downstream opportunities. As you probably know there are discussions about the possibility of opening export terminals, both on the west coast and on east coast to North America.

The other possibility of course is to find other usage for propane and in particular in derivative petrochemical applications like propane dehydrogenation unit. At this point we don’t have anything that sort of under front burner but we are watching the development of some of those opportunities with some interest.

Yeah, I mean, the distinct advantage we had with AEF is that we were able to buy an existing facility at attractive price and anything to do with PDH would require Greenfield investments so that would be much more significant investment.

Speaking of attractive price facilities, notice that was in sort of a exit nonstrategic asset mode, is there a possibility that you could get more of the fractionators in for (inaudible)?

All I can say Steven is that they haven’t indicated that it’s for sale.

Okay, thank you, David. And finally could you please give us an update on customer demand for rail expansion at South Cheecham either inbound or outbound Cheecham?

Sure, we are certainly -- as I mentioned in remarks we are certainly both at South Cheecham and at the Alberta crude terminal in discussions with producers to sort of firm up the amount of additional demand that there might be. Certainly the indications are healthy in that regard.

I guess there is a lot of different factors that we’ll enter into how much additional capacity we want to build and when we will make that decision, but so far we are encouraged by the conversations we’ve had.

Well, that’s encouraging, thank you David. Those are my questions.

I was hoping that you could maybe comment generally on the capital cost increases that we have seen at the (inaudible) de-ethanizer projects as well as if you are able to go back and get higher associated this from your contracted customers?

Sure, Rob. I think part of what we are seeing in both of those you mentioned is some general cost inflation.

We still as a result have the high level of activity in Alberta. We still are seeing cost increases that are I guess it’s fair to say somewhat disappointing.

There are also in both cases though some elements of scope change that have affected the changing estimates. Without getting too specific our ability to adjust fees for the -- as a result of the additional cost is limited with respect to the initial contracts that we signed in those cases.

We are within the sort of the anchored contracts. We have limited ability to share the capital cost risk.

But certainly there is additional capacity on the [lumpy] pipelines and in the de-ethanizer. And as we set this for other customers that will come into that spare capacity the capital cost will certainly be a factor.

All right, that is helpful and maybe just a bit more broadly given how large your capital plan is relative to historical levels, what steps are you taking to ensure that the projects are brought into service on time and on budget?

Certainly been a focus for quite some time, I would say we’ve seen this coming for probably as about two years now and we have been ramping up all of the support that we need everything from engineering to regulatory to office space. So I'm comfortable, no, I shouldn't say I'm comfortable, I'm optimistic that we have things flowing in.

But it's certainly something that gets a lot of attention. It's the examples you just mentioned are situations where it's the external engineering and construction services that have been a bit of surprise.

And so, we're trying to make sure that we manage that as effectively as we can going forward.

Robert, I would also add on a couple of the projects we did, pipeline projects we did last year and the couple that we're looking at right now, ultimately, and that's getting build by the producer, because they are the ones that have the time constraints and want to be very focused on it. And these that get set are a function of the cost of that project.

So I think we have some comfort that it'll be priced accordingly, but also showing some of that construction time around amongst ourselves and our producer customers.

All right, that's great. And maybe just one very quick follow-up.

On the Wilson Creek pipeline, what plays is that targeting?

Well, initially it's targeting the Glauconite play, but it takes a pipeline out into the area that some of the Southern Duvernay is starting to be developed. So, we see those a little bit of pre-build for the Duvernay in the area too.

Alright, great. Thank you.

I might add, Jim was talking earlier about the Duvernay. We have seen significant growth in volume at a number of our facilities.

The Duvernay has really not been a big part of that volume growth yet. It's still something that we see as future, I think what's encouraging for us is we're seeing significant volume growth from zones like the Glauconite, the Cardium, the Mannville and then up at Simonette the Montney and we've seen growth in volumes at the Caribou as well and the Duvernay is volume that we have our eye on for the futures significant coals opportunity, but it’s really not a big part of the picture as of today.

Thanks for the color.

Thank you, Steve. This completes our 2013 third quarter results conference call.

If you have any other questions, please call us. Our contact information is in yesterday’s release.

Thank you for listening and have a good day.