Lavonne Zdunich - Director, Investor Relations David Smith - President and Chief Executive Officer Steven Kroeker - Senior Vice President and Chief Financial Officer Brad Lock - Senior Vice President, Gathering and Processing Dean Setoguchi - Senior Vice President, Liquids Business Unit

Robert Hope - Macquarie Securities David Galison - Canaccord Genuity Dirk Lever - AltaCorp Capital Andrew Kuske - Credit Suisse Rob Catellier - GMP Securities Matthew Akman - Scotiabank Robert Kwan - RBC Capital Markets Steven Paget - FirstEnergy Capital Ashok Dutta - Platts

Thank you and good morning. It’s my pleasure to welcome you to Keyera’s 2015 third quarter conference call.

With me are David Smith, President and Chief Executive Officer; Steven Kroeker, Senior Vice President and CFO; Brad Lock, Senior Vice President, Gathering and Processing business unit; and Dean Setoguchi, Senior Vice President, Liquids Business unit. In a moment, David will provide an overview of the quarter, Brad and Dean will discuss their business units, and Steven will provide additional information about our financial results.

After that, we will open the call for questions. Before we begin, 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 outcomes, 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, inventory levels, and pricing of natural gas, NGLs, iso-octane and crude oil, the activities of producers and other industry players, our operating and other costs, the availability and costs of materials, equipment, labor, and other services essential for our capital projects, contractor performance, governmental and regulatory actions or delays, general economic conditions, and other risks as are more fully set out in our publicly filed disclosure documents available on our website and SEDAR. We encourage you to review the MD&A, which can be found in our third quarter 2015 report published yesterday and is available on our website and on SEDAR.

With that, I’ll turn it over to David Smith, our President and CEO.

Thank you, Lavonne, and good morning, everyone. Thanks for joining us today.

I am pleased to report that Keyera had another strong quarter, a record one, in fact. Adjusted EBITDA was $188 million, 24% higher than in the third quarter of 2014, and year-to-date adjusted EBITDA was up 32% over the same period in 2014.

Our performance is a reflection of the stability of our business, our diverse cash flow streams, and the robust growth capital program that we began in 2013. Approximately 65% of our operating margin has been earned from our fee-for-service businesses year-to-date in 2015.

Distributable cash flow was $127 million in the quarter, resulting in a payout ratio of 49% for the third quarter as well as year-to-date. Our payout ratio remains the most conservative amongst our peer group, even after increasing our dividend twice this year.

Keyera has delivered shareholders 14 consecutive dividend increases and a 9% compound annual dividend growth rate since we went public in 2003. Steven will speak more about our financial results later in the call.

We recognize this is a challenging and uncertain time for the oil and gas industry and for our customers. The low commodity price environment has resulted in a slower pace of drilling and development in Western Canada compared to last year.

To date, we have not seen a material impact on our operations, as producers are continuing to develop resource plays around several of Keyera’s core facilities, including the Rimbey, Strachan, Brazeau River, Simonette, and Minnehik Buck Lake gas plants. However, we realize the success of Keyera relies on our customers and their competitiveness in the global market.

As a result, we continue to work with our customers to provide services as efficiently as possible. Our vast network of gathering systems and processing solutions provides customers with redundancy and flexibility, and thereby increases reliability of service.

With decades of operational experience, we strive to operate our facilities safely, reliably and efficiently to reduce overall operating cost for our producers. For our oil sands customers, our condensate hub provides the most receipt and delivery points and offers customers a flexible and reliable system to source and trade condensate.

And our marketing group’s knowledge and access to storage, transportation options and markets help ensure our producer customers receive the best prices for their NGLs. With that introduction, I’ll turn it over to Brad Lock to discuss our gathering and processing business unit.

Thanks, David. The gathering and processing business unit had a strong quarter, delivering an operating margin of $69 million, representing an increase of 28% over the prior year, as we are generating incremental cash flow from our latest capital investments.

This includes the new Alder Flats gas plant and the turbo expander at Rimbey. The Alder Flats gas plant was completed in May by Bellatrix Energy and we are pleased that it is operating near its capacity of 110 million cubic feet per day.

We have a 35% ownership interest in the gas plant and Bellatrix is the operator. The 400 million cubic feet per day turbo expander at Rimbey was completed in July and is also operating well.

The turbo expander allows us to extract ethane from the raw gas at the plant, which we are selling to a large Alberta consumer under a long-term sales agreement. In September, the Zeta Creek gas plant was completed by Velvet Energy and commissioned and started up by Keyera and is adding incremental cash flow in the fourth quarter of this year.

We operate the 54 million cubic feet per day gas plant and have a 60% ownership interest. Turning to our volumes, as David mentioned, to date we have not seen a material impact in our operations due to low commodity prices.

Year-to-date, our net processing volumes are consistent with the same period last year and our third quarter net volumes were consistent with those in Q2. Our third quarter volumes were affected by a planned maintenance turnaround at the Minnehik Buck Lake gas plant, an unexpected week long outage at the Simonette gas plant and continued curtailments imposed by TransCanada on its sales gas pipelines.

These curtailments are resulting in lower throughput volumes at several of Keyera’s gas plant, but most notably Strachan, Brazeau River, and Minnehik Buck Lake. Looking forward to 2016, we are cautiously optimistic about our throughput volumes, as producers remain reasonably active around many of our gas plants.

We have only two turnarounds planned at Nevis and Nordegg, and there may be some relief from TransCanada’s pipeline restrictions. I will now turn it over to Dean to discuss the liquids business unit.

Thanks, Brad. The liquids business unit also delivered strong results in the third quarter, with both the NLG infrastructure and marketing segments performing very well, generating operating margin of $56 million and $99 million, respectively.

NGL infrastructure’s results grew by 22% over the same quarter last year, due to increased demand for diluent handling services, high utilization of fractionation and storage assets, increased activity at select rail terminals, and the new de-ethanizer facility at KFS that became operational in April. Progress was made on a number of projects that will support the infrastructure needs of the industry, including ongoing construction of the 35,000 barrel per day fractionation expansion and development of additional underground storage capacity at Keyera’s Fort Saskatchewan complex.

We recently placed our 13th cavern into service and continued to develop our 14th and 15th caverns. At our Base Line crude terminal, oil terminal project, Kinder Morgan is continuing to make progress on the regulatory front and site grading should begin soon.

The Norlite Pipeline, a joint venture with Enbridge, continues to progress as well. During the quarter, regulatory approval was received and construction work began.

To further enhance the capacity and reliability of Keyera’s industry leading condensate system, we have agreed to acquire a 50% interest in the southernmost portion of the proposed Grand Rapids Pipeline once it’s complete. The pipeline will be constructed by the Grand Rapids Pipeline Limited partnership, an affiliate of TransCanada and Brion Energy Corporation, and will provide Keyera with proprietary access to at least 225,000 net barrels per day of additional diluent transportation capacity between Edmonton and Fort Saskatchewan.

Moving to our marketing segment, the third quarter operating margin was 24% higher than the same period in 2014, primarily due to a robust iso-octane business. Keyera continued to benefit from soft butane feedstock prices, strong demand for gasoline especially during the summer driving months and a weaker Canadian dollar.

In addition, our effective risk management strategy continued to deliver the results we expected. It’s important to note that for 2016 our marketing results will be affected by a six-week planned maintenance turnaround at our AEF facility where we produce iso-octane.

A turnaround is scheduled at AEF every four years to ensure safe, efficient and reliable long-term operation. The cost of the turnaround is estimated to range between $40 million and $45 million.

Looking ahead, we’re confident in the outlook for the liquids business unit. Our fractionation, storage and logistics services complement Keyera’s gathering and processing business.

In addition, our cash flows are diversified, with a variety of services related to diluent, solvent, crude oil and the production of iso-octane. In 2016, we expect a full year of incremental cash flows from several capital projects that were completed in 2015, such as the 30,000 barrel per day de-ethanizer at KFS and the Josephburg rail terminal.

In addition, we’ll also benefit from new projects to be completed in 2016, such as the fractionation expansion at our KFS facility. With that, I’ll turn it over Steven to discuss the financial results in more detail.

Thanks, Dean. As David mentioned earlier, we were pleased with how all segments of our business performed during the third quarter of 2015.

Adjusted EBITDA was a record at $188 million. As a result, trailing 12 months’ adjusted EBITDA continues to grow and is now at $657 million compared to $530 million for 2014.

Recently, we completed a number of strategic growth initiatives that are adding incremental cash flow to our results, such as the Alder Flats gas plant, the turbo expander at Rimbey, the de-ethanizer at KFS and our Josephburg rail terminal. Iso-octane sales are also continuing to provide strong cash flow despite lower oil prices.

Net income for the quarter was strong at $110 million compared to $82 million in the third quarter of 2014. This increase was despite a $16 million impairment charge related to Keyera’s oil and gas reserves due to lower commodity prices.

Year-to-date, our growth capital investment excluding acquisitions was approximately $512 million and on track with our guidance of $700 million to $800 million for the year. Across our business, from 2013 to the end of 2015, we expect to have invested over $2 billion of growth capital, supported primarily by fee-for-service contracts.

Maintenance capital year-to-date is $59 million, while maintenance capital for 2016 is expected to be between $85 million and $95 million, including costs for the scheduled turnaround of the iso-octane facility. The increase in estimated maintenance capital for 2016 compared to the approximately $65 million estimate provided for full year 2015 is more than offset by expected savings in cash taxes in 2016.

Cash taxes year-to-date are $65 million, and Keyera still expects full year 2015 cash taxes to be between $85 million and $95 million. However, we expect our cash taxes to be significantly lower in 2016, estimated at between $10 million and $20 million, due to increased capital cost allowance deductions related to several major capital projects that became available for use in 2015.

Keyera is well positioned financially, with one of the strongest capital liquidity positions amongst our peers. At the end of the third quarter, our net debt to EBITDA ratio was 2.4 times compared to our strictest bank covenant of 4 times.

With a strong balance sheet, low payout ratio and access to capital, we are well positioned to prudently fund the rest of our 2015 capital plan and to selectively pursue acquisition opportunities. In addition, our DRIP programs generate approximately $40 million each quarter.

That concludes my remarks. David, back to you.

Thank you, Steven. At Keyera, our network of interconnected gas plants, pipelines, and facilities, as well as our diverse service offering, continue to generate impressive results and position us for future success.

Looking forward to 2016, we are optimistic that we are well positioned to weather this difficult period. We expect to benefit from the capital investments that we’ve made over the last few years as projects ramp up and generate incremental cash flow.

Further, demand is expected to increase for our condensate related services as oil sands production grows with the recent startup of several projects, including Husky’s Sunrise project and Imperial Oil’s Kearl Phase II project. At Keyera, we take a long term view of our business.

We are confident in the competitiveness of the areas of the western Canada sedimentary basin in which we operate and we’ll continue to invest for future growth. Next year, we expect to invest between $600 million and $800 million of growth capital, focused on NGL infrastructure projects such as the frac expansion at KFS, the Norlite Pipeline project with Enbridge, the Base Line crude oil storage terminal project with Kinder Morgan in Edmonton and the continued expansion of our condensate network in the Edmonton/Fort Saskatchewan area.

These projects are backed by customer contracts and are expected to add meaningful incremental cash flow in 2018 and beyond. We are confident in Keyera’s future, given our flexible and diverse assets, our consistent business strategy, our financial discipline, and especially our people.

On behalf of Keyera’s directors and management team, I thank our shareholders for their continued support and our employees for their hard work and dedication. With that, I’ll turn it back over to the operator.

Please go ahead with questions.

Maybe just taking a bit of a step on the M&A front, can you update us on your thoughts there, given the potential for significant sized assets to be on the market? Do you expect to stick to your core areas, or would you look to reach out to potentially add a new business line or a new geographic area?

We make it a policy not to comment on specific opportunities. But I guess as a general comment I would say that we’re always looking for opportunities that meet our economic criteria as well as being a strategic fit.

I think we wouldn’t rule out moving into a different kind of business, as we did when we bought AEF almost four years ago now. But I think we’re always focused on opportunities where we bring something to the table, where we have the ability to grow the business with the capabilities that we can bring to bear on the asset.

And so that really represents the lens that we look at opportunities with. In terms of the opportunities that we see within western Canada right now, I think it’s fair to say that producers are looking at their assets and looking at their balance sheets and trying to find ways to continue to fund their growth activities.

And so we are certainly having discussions, in many cases, with companies that are looking to either sell assets or have third parties build assets for them. But as I said, it’s really not appropriate for us to comment on any of those at this state.

One follow-up on the NGTL system, so you made some comments about how restrictions should decide by the end of the year, looking out to 2016, do you expect to see a relatively constrained system again, or should the majority of these issues be behind you?

It’s hard to predict exactly what’s going to happen. TransCanada has indicated that there’s additional capacity being made available in the later part of this year, but it’s hard to say how much of that capacity is already undertaken with contracts.

So I think we’re cautious that there’s no clear open season for capacity on the pipeline and we’ll be continuing to deal with restrictions over the course of 2016. To what degree is certainly uncertain.

So I just wanted to touch quickly on the NGL infrastructure segment. And maybe I’m not looking at this properly, but when I adjust for the intersegment eliminations, there was a negative operating profit in the quarter where in the first half we had a slight profit.

Just wondering what was behind that, or if maybe I need to look at this a different way.

I’ll let Steven maybe answer specifically, David. But one of the things to be aware of is that a significant portion of the capacity in some of the NGL infrastructure assets is utilized by our marketing group for the NGL volumes that they handle.

And so if you take out those intersegment revenues, you’re taking out a significant portion of the utilization of the facility. So, that’s why the profitability, after elimination of those revenues that they earn from the marketing group, that’s why the profitability looks a fair bit lower.

That’s why we represent our operating margin that way, is to try and show it on a completely third party independent basis. I’m not sure if that answers your question.

So how should we think of it, should it be kind of like a slight negative or slight positive going forward or break-even or how should we think about it when we look at modeling that segment?

First of all, I would direct you to the operating margin number, because I think that represents, in our view, the true measure of the profitability of the NGL infrastructure assets. If you eliminate those internal revenues, I think the answer to your question will then depend on the degree of utilization of the facility by internal customers versus external customers and that’s a little hard to predict.

Then my second question would just be regarding the turnaround plan for AEF. Just wondering, considering that’s around your peak time, I believe, is there any opportunity to maybe make up some of the lost production from the turndown either before or after or what are your thoughts there?

The turnaround is scheduled for September of 2016, so really right after summer driving season, but before we get into full on winter, hopefully. It’s a six-week planned turnaround.

We do run the iso-octane facility at full capacity, so really not much opportunity to increase our production rates more than what we run in that already. So not really a lot.

We will have some iso-octane stored to fulfill some of our sales contracts during that time, but otherwise we will be losing six weeks of production.

My question is more directed to Brad. And Brad, if you could, give us a little color on what the net volume impact would be in the third quarter from TransCanada curtailments and the planned turnarounds.

It kind of varies month to month, but I think on average we think it’s about 80 million standard cubic feet a day that is related to TransCanada curtailments. And I think over the course of the quarter, our turnaround impact at Buck Lake was probably around 15 million standard cubic feet a day normalized over the quarter.

Just on the marketing business, you had a pretty impressive number that you posted, just in a outright sense and then also on a margin comparing to last year. So maybe you could just talk a little bit about what contributed to margin expansion.

Clearly, in the MD&A you talked about iso-octane prices, US dollar impact and really just the market on butane being all contributing factors. Could you give any kind of proportionality of those factors, on what really drove the 20% margin versus 10% a year ago?

We don’t generally comment on the proportion. We do acknowledge that a significant proportion comes from AEF.

I think it’s also important to remember that part of the reason why we do that is because it is a seasonal business and is mixed with other products that are seasonal. And so again, obviously as mentioned before and as Dean mentioned, very strong results in Q2 and Q3 from a compilation of factors, right?

The softer butane prices, the high utilization, the strong gasoline prices, and as well the premium for our product was very strong and the FX worked in our favor. But no doubt a large proportion of the marketing cash flow comes from iso-octane.

I would comment, though, that all the products generated positive margin in Q3.

And then just on the turnaround at AEF, maybe just a little bit of clarity. So the $40 million to $45 million of cost, is that strictly capital cost, and that’s not factoring any impact from downtime and not having the facility available?

That’s right. It represents the maintenance cost of that actual turnaround, so not the actual operating cost during that time.

I’m wondering what your thoughts might be on dividend policies here going forward. Obviously, your payout ratio is low as you pointed to, but you’re also in a pretty severe downturn for the industry.

So could you first comment on that?

Our policy really hasn’t changed. I mean, we’ve always taken the view that we like the track record we have of steady gradual increases in the dividend per share, and we focus on what the distributable cash flow is per share and what our outlook is for the distributable cash flow per share when we make our decisions around dividend per share.

We continue to be optimistic about the outlook for the business and that’s why we’ve increased the dividend twice this year. But those are the factors that inform our decision each time.

And we don’t have a specific target for the payout ratio and we also don’t have a specific target for the growth rate. I think it depends on the factors at play.

You’re right. It is a time for caution, I think, given the slowdown in industry activity.

So I think our stance will be to be a little bit cautious. And as we get into 2016, we’ll reassess how we see the direction of industry activity.

And just strategically, where does building your position in the Montney rank relative to other strategic priorities? You commented on M&A and how you look at that.

You’d have to bring something to the party. But when you’re looking at asset acquisition opportunities, how does the Montney rank in that?

And would you consider partnering with a financial player to execute that strategy?

I think the Montney resource is certainly – from our point of view, it’s certainly one of the strongest and most economic resource plays in North America. And I think the growth from the Montney is poised to continue.

Drilling activity certainly across the basin is down in 2015. But if you look at where that drilling activity is focused, a lot of it is in the Montney.

So I think that’s an indicator. So certainly it is an area that we would look to establish a stronger footprint.

The challenge for us is simply finding the right opportunity, looking for – we certainly are keen to have a bit of a better footprint, but we’re going to maintain our discipline with respect to the economic criteria. I think it’s fair to say that a lot of the producers at this point are taking a little bit of a pause with respect to their future plans.

But we continue to have discussions with those producers to see what kind of opportunities might make sense for us.

And partnering with a financial partner?

That’s certainly something that we would consider, Rob. We have had some discussions along those lines.

Clearly, there’s a fair bit of private money that’s out there looking for opportunities in our industry. And I think in the right circumstances partnering with one of those players might make a lot of sense.

Then turning our attention to AEF business, we’ve seen RBOB trending down in the normal seasonal pattern, but there’s also the influence of butane. And I’m just wondering, before considering the impacts of hedging, how do you see those margins trending year-over-year?

And then separately, can you comment on the relative effectiveness of your hedges, given the recent price decline?

First of all on AEF, we really had a very good year. As you know, RBOB prices were very strong last summer.

Gasoline demand hit 10 million barrels, and even today I think it’s still around 9 million barrels. It’s almost a summer consumption number.

So very high and really helped – the low WTI prices really helped translate into lower gasoline prices, which increased consumer demand. So in a sense it’s a little bit countercyclical for our business and we benefitted from that.

Looking forward, it’s hard to really predict that the same factors will be present for next year, partly because gasoline prices are influenced by Brent and the Brent WTI prices have compressed since last year. RBOB futures aren’t quite as robust as what we realized last year.

So those are all factors that don’t look quite as strong as what we were able to recognize this year. Butane prices are still soft and there’s still a lot of butane supply out there.

So it’s looking at this point that butane prices are going to remain soft. So all together, we think that we’ll have a pretty strong year next year, but perhaps not as strong as 2015.

With respect to our hedges, again, I continue to reinforce the fact that we’ve gone through a lot of price volatility over the last year or two. And through a high price to a rapidly declining price scenario, our marketing book has been very stable.

So our hedges and our hedge strategy have been very, very effective.

It’s actually Matthew Akman. My question is on Grand Rapids and your opportunity there.

And in your introductory comments, you mentioned that it gives you proprietary access to the diluent pipeline, which is obviously a good thing, whether you could discuss some of the potential areas of opportunity within the infrastructure business and also whether you’d be prepared or whether you plan to take condensate on a proprietary basis. Or I guess said another way, would you own capacity on the pipeline?

The way I would describe our arrangement with the owners of Grand Rapids pipeline is really it’s just an incremental expansion of the condensate network that we’ve been building out really for the last 10 or 12 years. We recognized that one of the bottlenecks that we will face in the future is the pipeline transportation capacity on our existing system between Edmonton and Fort Saskatchewan.

We had been looking for – or looking at building another pipeline link ourselves. But when we learned that TransCanada and Brion were going ahead with the southern segment of their Grand Rapids pipeline, we approached them and explained to them what we saw as the merits of joining forces.

So once that pipeline is constructed, we will purchase the segment of the diluent pipeline between Edmonton and Fort Saskatchewan. And we will operate it and we will integrate it into our existing network, which gives us access to at least 50% of the pipeline capacity that we will own, which is roughly 225,000 barrels.

So it essentially doubles the transportation capacity that we have available within our condensate network. And then we will tie it in with our terminal and storage infrastructure at Edmonton and into our fractionation and storage facility at Fort Saskatchewan.

And the opportunities that we referred to are simply the opportunities to continue to build the customer base and the volume of business for storage terminal and transportation capacity within the condensate network.

Yes. So, it’s not a fixed return type deal.

It adds to infrastructure for you guys. And then, whatever you can make using it for marketing or NGL infrastructure fees you’ll make.

Yes, that’s the way to look at it. I think when we first announced the deal earlier this summer, we explained that we already have in place some long term contracts for condensate transportation that have volume growth built into them.

So some of that capacity is in essence already spoken for with existing contracts, but there will be substantial capacity that we have available to contract up with additional customers.

If I can just actually follow up a little bit on the last question, we’ve been talking for a while about, as volumes grow, the potential constraints you’re going to have between Edmonton, Fort Saskatchewan and the need to expand the pipe you have in the ground. So if you think about what Grand Rapids adds and kind of the other initiatives that you’ve got going right now, does that kind of give us a really good runway now that we don’t have to be thinking about major expansion coming out of Edmonton?

Well, I think in our view, Robert, it takes care of the near term outlook, certainly the growth in volume that we see over the next five to 10 years. I think the answer to your question in terms of the longer term future will really depend on what your outlook is on future growth of bitumen production from the oil sands, because that’s ultimately what will drive the demand for our services.

Robert, just to add to that, when I say that, I’m talking about the pipeline capacity. We continue to grow the storage capacity on our system.

We continue to see growth in demand for storage, particularly underground storage at Fort Saskatchewan. And there may be other elements of the network that we continue to invest in terms of terminal capacity.

But with respect to the transportation capacity that we need in the corridor between Edmonton and Fort Saskatchewan, I think it’s our view that the arrangement with south Grand Rapids will take care of our needs for the medium term.

Yes, certainly in the foreseeable future, I mean, if you look at the amount of condensate that could come into the south end of our system from Edmonton, we believe that there is plenty of capacity now to basically handle those movements of condensate from Edmonton upwards. I guess there would have to be a significant amount of volume that would have to come in from the south end which would require more capacity beyond what we’re adding with Grand Rapids.

So effectively you can move all the conde on the new Grand Rapids systems and it allows you to optimize the service of the other pipes you have in the ground. So to some extent, are you not also opening up capacity for both kind of propane, butane and mix movement?

No, this is just for condensate. But I’m just saying, if you look at the sources of condensate from the south end of our system, it would be more or less the CRW pool or Southern Lights.

And again, we’re able to accommodate the volumes off of those systems with the capacity that we’re adding now.

As you look at the $600 million to $800 million for growth CapEx for 2016, how much of that’s already fully secured and how much of that is in just kind of general bucket for initiatives that you think might come up over the course of next year?

The lower end of that range is basically the sort of buttoned down capital from the NGL infrastructure projects, again, projects that are approved and moving forward already. So that would be our share of capital spent on Norlite, the Base Line terminal, our continued investment in our condensate system, including the pumps related to the south Grand Rapids pipeline that we’re responsible for, those kind of initiatives.

And just the last question coming to iso-octane, you’ve spoken about the increasing premiums. I’m just wondering how do you see that playing out?

Thoughts on the market, some things that we’ve been reading about lower octane and changing mix of US production, there’s kind of the demand for octane products and increased demand for high octane gasoline, are those things that your customers are talking to you about with respect to wanting your product or are there some other factors that we need to think about that could change over the course of the next year or two?

I think you’ve addressed, I guess, one of the issues. What’s happening in the US is that the – a lot of the feedstock for the refineries is coming from the shale oil, which is lighter and requires more octane.

So that with increased gasoline demand certainly has increased the premiums for octane and we’re seeing that. I think what we’ve also done is that we’ve opened, using our rail logistics expertise, we’ve really opened up the market for iso-octane right across North America.

So we are shipping to a lot of other destinations other than our storage at Galena Park in the Gulf Coast. So a lot of our product gets moved into the Midcontinent as well now and out East.

So we do see a continued strong demand for octane. It’s not something we can hedge.

That premium is locked in contractually. And we do think that will likely be strong into 2016.

And how often is the premium renegotiated under the contracts?

We have varying contracts, some that are longer in term and some that are shorter in nature. So it just depends on the contract.

And as you think about some of the short term contracts and the downtime for the six weeks, you’re going to be taking some octane out of the mix, supply mix. So is there a potential offset where the premium is kicked out just a bit to compensate for that?

I don’t think that we supply enough octane to market. I mean, we compete with other octanes as well.

And let’s face it, our 13,500 barrel a day facility is a drop in the bucket when you think of the 10 million barrel a day gasoline pool. A six week turnaround I don’t think will materially change the premiums for octane.

All your operating margins together look like they were up about $45 million year-over-year and you’ve deployed a good deal of capital since third quarter 2014, but FFO is pretty much flat at $147 million. And part of that appears to be an increased cash tax, but are there other factors we should consider?

No, I think the cash tax is one of the primary factors. There are other ins and outs in terms of LTIP expense and things like that, but cash taxes really are the driver that sort of kept a lid on distributable cash flow per share, to keep it flat to last year.

Again, we are expecting cash taxes to drop off significantly next year just due to the strong deductions we had in the tax pools there. And as well, maintenance capital is always an issue there too in terms of distributable cash flow.

Given what happened with Alliance, would you be able to give us an operational update on Simonette? What happened with the outage and what’s happening now?

Steven, I’ll take that one. I think it’s premature to talk specifically about the incident.

Obviously, we’ve put a lot of time and resource into the investigation and making sure we understand what happened and, more importantly, what the lessons are that we can learn from that so that hopefully it’ll never happen again. What I would emphasize is that there was no danger to the public.

There was no release of gas and there was no damage to our system or to the Alliance system. And our plant was operational very quickly after the incident happened.

What we’ve been working on is to determine what the cause was of the upset and also why our analyzers and meters allowed the gas to get into Alliance. So those are the issues that we’re working through.

This question is probably for Dean. Could you please comment on activity levels at Josephburg?

What’s driving activity levels there, and how much impact did Josephburg have on marketing results in the quarter?

At Josephburg, we commissioned the terminal this summer. We have been moving propane out of that terminal, but lighter volumes right now.

We’re getting into the winter months so that’ll start to pick up more. And really we built that facility to handle the incremental propane that will also be coming off of our second frac, which again, will be online in the second quarter of 2016.

Has any capacity at Josephburg been contracted by Keyera itself or anyone else?

No, it’s really utilized by our marketing group. So again, we purchase our liquids behind gas plants and the purchase price that we pay for those NGLs are net of transportation and fractionation and also we net off the terminalling as well.

At this point, it looks like there might be West Coast based export capacity for much of the surplus propane in western Canada. What might that mean for Keyera in the coming years?

Well, I think that any outlet – I mean, what our basin needs is market access for every product. And obviously, with the weakness in propane prices, we need to have more outlets to clear the market.

And West Coast would be – more capacity at West Coast would be very helpful. Right now, I think about 90% of the propane barrels that are produced are basically exported out of western Canada, so either out east in Canada, to the US or to Mexico.

To the extent that we can get it efficiently to the West Coast would be great for the overall markets in Edmonton, and obviously benefit our business as well.

On that vein and my final question, there has been some talk about Mexican markets opening up. You’ve got a terminal not that far from Mexico.

What might it mean for Keyera?

I can say that our marketing group is accessing the best markets for propane. Our railcars or our propane reaches over 300 destinations across North America.

And again, some of that propane is going to some border locations in Mexico.

I had a quick question regarding your crude by rail terminal. How is that coming along?

And presume you were talking in terms of an expansion plan. That’s not likely to happen as we speak or given the current market condition.

A - David Smith I assume that you’re referring to our Alberta crude terminal, which is located in east Edmonton, which is a joint venture with Kinder Morgan.

Yes.

That facility is moving as much crude oil as we can. It’s really operating at full capacity.

There are a variety of reasons for that. One is the fact that we can access the variety of crude streams that Kinder has at their facility at their terminal.

And in addition, the customer for that facility is Irving Oil for their New Brunswick refinery. And they’re anxious to get as many barrels of western Canadian crude as they can, because their alternative is to buy more expensive crude oil off the ocean from overseas suppliers.

And so our facility there has been a steady contributor. In terms of expansion possibilities, it is something that we have looked at and considered.

We don’t have any imminent plans. But certainly, I think as things evolve in the industry, that’s one of the potential growth projects on our plate.

And just a quick follow up on that. So when you say full capacity, it’s about 40,000 barrels a day?

Theoretically it could do close to 40,000 barrels a day, but we’re somewhat constrained by the ability of the railways to move the cars in and out of there. So the actual utilization, we’re doing as much as we can subject to that constraint.

The actual utilization is probably somewhere in the 75% range currently.

Thank you, Chris. This completes our third quarter 2015 conference call.

If you have any other questions, you can please contact the Investor Relations group. Our contact information is in yesterday’s release.

Thank you for listening and have a good day.