Keyera Corp.

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

Linda Ezergailis - TD Securities David Galison - Canaccord Genuity Inc. Robert Catellier - CIBC World Markets Andrew Kuske - Credit Suisse Steven Paget - FirstEnergy Capital Robert Kwan - RBC Capital Markets Patrick Kenny - National Bank Financial Ashok Dutta - Platts Leah Jordan - BMO Capital Markets

Thank you, and good morning. It’s my pleasure to welcome you to Keyera’s 2016 first quarter conference call.

With me are David Smith, President and Chief Executive Officer; Steven Kroeker, Senior Vice President and Chief Financial Officer; Brad Lock, Senior Vice President, Gathering and Processing Units; and Dean Setoguchi, Senior Vice President, Liquids Business Unit. In a moment, David will provide an overview of the quarter, followed by business updates from Brad and Dean.

Steven will provide additional information about our financial results. We will open the call for questions once we complete our prepared remarks.

Before we begin, I would like to remind listeners that some of our 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 general economic, market and business conditions; 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 costs and other costs; the availability and costs of materials, equipment, labor and other services essential for our capital projects; contractor performance; counterparty risk; governmental and regulatory actions or delays; competition for among other things; business opportunities and capital; 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 2016 first quarter report published yesterday and is available on our website and SEDAR. With that, I’ll turn it over to David Smith, our President and CEO.

Thank you, Lavonne, and good morning, everyone. I am pleased with Keyera’s results for the first quarter of the year.

While the challenging economic environment persists for the energy sector, Keyera continues to generate strong results driven by our predominately fee-for-service business and contributions from our ongoing growth capital program. Adjusted EBITDA for the first quarter was $145 million, as all three business segments performed well.

Our gathering and processing business unit reported a 13% increase in operating margin compared to the same period last year as gross throughput volumes increase by 2%. Our liquids infrastructure segment reported a quarterly operating margin 15% higher than the first quarter of last year.

And marketing’s results were strong again this quarter with an operating margin of $44 million, compared to $36 million a year ago even with lower iso-octane volumes due to some unscheduled downtime at Alberta Envirofuels. Net earnings were $70 million or $0.41 per share, compared $57 million or $0.33 per share in the same period in 2015.

Distributable cash flow was $116 million for the quarter, resulting in a payout ratio of 56%, which remains one of the most conservative in our peer group. Steven will speak more about our financial results later in the call.

Keyera’s first quarter results demonstrated the effectiveness of our strategy and our integrated portfolio of assets. Overall gross throughput volumes at our gas plants remained steady compared to both the fourth quarter of 2015 and the same quarter last year.

Demand for our diluent handling services continues to grow, as both new oil sands projects and phased expansions of existing projects begin operations. And the AEF continues to add value as we convert low value butane into iso-octane, a high-value gasoline additive which attracts a premium sales price.

While we recognize this is a challenging time for our industry, we take a long-term view of the business. We continue to invest in new capital projects, look for acquisition opportunities, and work with our customers to provide efficient and cost-effective midstream services and solutions.

With that, I’ll pass it over to Brad to discuss our gathering and processing business unit.

Thanks, David. The gathering and processing business unit reported a strong quarter with an operating margin of $68 million, as gross average throughput volumes remained steady at 1.56 billion cubic feet per day, slightly ahead of our throughput volumes in the previous quarter and the first quarter of 2015.

Our consistent volumes were in part of due to previously curtailed volumes on the TransCanada Pipelines system resuming production as restrictions were lifted at late 2015. These throughput volume gains were partially offset by the natural production declines, plus drilling activities surrounding certain Keyera gas plants and producers shutting in gas due to low commodity price environment, which we estimate at approximately 2% of our gross throughput volume.

Although gross throughput volumes increased quarter-over-quarter, operating margin decreased as the fourth quarter of 2015 included final fees collected for the turnaround extracted in 2014. While we are pleased with our throughput volumes year to date, we remain cautious with respect to our outlook for the remainder of 2016, given reduced producer capital budgets and activity.

Continued maintenance on the TransCanada Pipelines system may have a limited impact on our volumes and we have one turnaround at the Nordegg River gas plant planned for the third quarter. As David mentioned, we take a long-term view of this business, continue to work with our customers to provide efficient and cost-effective midstream services.

Since most of our operating costs flow through to our customers, we are working diligently to reduce costs in order to help producers realize better net values. I will now turn it over to Dean to discuss the liquids business unit.

Thanks, Brad. Liquids business unit performed very well in the first quarter of 2016.

The liquids infrastructure segments generated an operating margin of $62 million, a 15% increase over the same period last year. The segment’s record results were primarily due to the continued growth in demand for our industry-leading condensate system as well as the steady use of our de-ethanizer, fractionation facilities, storage assets, and rail terminals.

We’re pleased to confirm that the 35,000 barrel per day fractionation expansion at KFS is currently being commissioned and is expected to enter commercial operations in June. The completion of this project is expected to increase the utilization of our Josephburg Rail Terminal as well as our underground storage caverns, which we continue to expand.

We’re currently washing our 14th and 15th caverns that are scheduled to be completed in 2017. Later this year, we expect to commence drilling of our 16th and 17th caverns.

Our three major capital projects with joint venture partners are all progressing well. The Norlite Pipeline project with Enbridge remains on schedule and is expected to be in service mid-2017.

Civil-work progressed during the quarter at the Base Line Terminal’s crude storage project with Kinder Morgan. Regulatory approvals have also been received, allowing construction of the tanks to begin in the second quarter.

The first tanks are expected to be commissioned in the second-half of 2017. Engineering work progressed on the pump station associated with the Grand Rapids pipeline projects with TransCanada and Brion Energy.

Project is on schedule and is expected to be in service during the second-half of 2017. At this time, we are pleased to report that costs are trending lower than budgets for these major projects.

To further enhance our infrastructure around our Hull Terminal near the U.S. Gulf Coast, we acquired 88 kilometer pipeline system in East Texas for US$24 million.

The pipeline originates at the Beaumont refinery petrochemical complex, extends to our Hull Terminal terminates near the Mont Belvieu energy hub. Going forward Keyera will invest between US$25 million to US$30 million to connect and repurpose the system to optimize its use.

We are currently targeting to have the pipeline in service by 2018 to transport NGL mix and specification products between the Hull Terminal and refiners, marketers, and exporters assuming commercial agreements and pipeline connections progress according to plan. For the rest of 2016, we look forward to continuing to serve our valuable oil sands customers as new projects and project expansions are completed, resulting in increased demand for our condensate services.

The marketing segment generated steady results by leveraging Keyera’s strategically located storage and transportation assets, the team’s knowledge of regional markets, and our effective risk management practices. Operating margin was $44 million even with lower iso-octane sales volumes due to unscheduled maintenance and repair work at the AEF, which reduced plant utilization to about 80% for the quarter.

As previously discussed, in September we will begin a six-week turnaround at AEF that is expected to cost $40 million to $45 million. The loss of associated production during this period will also reduce our iso-octane sales volumes.

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

Thanks, Dean. As mentioned earlier, we had a successful quarter with all three business segments generating strong results despite the prolonged downturn.

Approximately 74% of our operating margin, were [indiscernible] in the first quarter of 2016. Adjusted EBITDA for the first quarter of 2016 was $145 million compared to $185 million in the same quarter of 2015.

This included approximately $40 million of nonrecurring cash gains related to the expansion and fiscal risk management contracts that substantially offset our 2014 year-end inventory write-down. Adjusted EBITDA in the first quarter of 2016 were over $18 million in incremental EBITDA due to several growth projects completed in 2016.

Adjusted EBITDA in the first quarter of 2016 was reduced by $6 million due to costs related to underutilized rail cars, $6 million in [indiscernible] engineering development costs, the fact AEF ran at an average utilization rate of 80% during the quarter. Distributable cash flow was $116 million, compared to $140 million in the first quarter of 2015 was again included the nonrecurring cash gains of $40 million mentioned earlier.

Distributable cash flow in the first quarter of 2016 also benefitted from $16 million reduction in cash taxes versus the same period a year ago. For the full year, we still expect Keyera’s cash taxes to be between $15 million and $25 million, and they are largely based on 2015 taxable income from the partnership that was allocated to Keyera Corp.

in 2016. Keyera continues to benefit from increased capital costs allowance reduction to several major capital projects that are now available for use.

Net earnings for the quarter were $0.41 per share, compared to $0.33 per share in the same period of 2015. Higher operating margin from all business segments and lower long-term incentive planning spend, more than offset higher finance and depreciation charges associated with Keyera’s growing asset base.

We continue to invest in assets that expand our core infrastructure, provide operational flexibility and are expected to generate a steady stream of cash flows in the future. Our growth capital program remains on track, and after refining our processing project schedules we’ve narrowed our growth capital we target to approximately $600 million, which is at the low end of the previously announced range of $600 million to $700 million.

We have the financial flexibility to fund this program, taking advantage of acquisition opportunities that may present themselves. Our net debt to EBITDA ratio is 2.4 times at the end of the quarter, compares to our strictest bank coming in at 4 times.

We have a $1.5 billion committed Credit Facility that only had $369 million drawn at March 31, 2016. We have a low payout ratio at 56% for this quarter.

That concludes my remarks. David?

Thank you, Steven. While the difficult economic environment persists for the energy sector, the devastating wildfires in Fort McMurray have added more challenges.

Like many others, we had to evacuate our South Cheecham Rail and Truck Terminal which is located about 70 kilometers southeast to Fort McMurray. All of our employees arrived safely in Edmonton, and based on our current information the terminal has not been damaged by the fires.

We are working diligently with our customers to help manage condensate inventories while oil-sands operations remain suspended. The residents of Fort McMurray are facing serious challenges.

At Keyera, we will do our part to assist our communities and our industry through this difficult period. Reflecting on the quarter, I am pleased with Keyera’s performance, as we continued to generate steady results in a challenging environment.

Our success is a testament to our disciplined approach, our high-quality asset base, and our talented team of employees. We are managing our business for the long term, working with customers to provide efficient and cost-effective midstream solutions.

On behalf of Keyera’s Directors and Management team I would like to thank our employees, customers, shareholders, and other stakeholders for their continued support. I am confident that we will weather this low commodity price environment while creating long-term growth and value for our shareholders.

With that, I’ll turn it back over to the operator. Please go ahead with questions.

Thank you. Good morning.

Good morning.

I’m just wondering, that was mentioned in your MD&A around the new NGL year and how as of April 1 fractionation rates on average will be lower compared to last year due to a number of factors. Can you comment on maybe how much of your facility on a percentage basis might be subject to that and an indication of approximately how much lower it might be?

Hi, Linda, it’s Dean Setoguchi. We don’t provide specific guidance on our fees, but what I can say is that our second fractionator that we’re currently commissioning and that will be on stream in June.

We have a lot of long-term contracts that have backed the construction of that facility. So we do have a mix of long-term and short-term contracts.

The short-term contracts are sort of the year to year and the long ones would be up to 10 years. So I guess it’s a blend.

And when you take that blend it’s going to be a bit lower than the last year in terms of our overall rate.

Okay. Thank you.

And just as a follow-up, can you can you comment on, maybe as it pertains to your marketing business, the new contract here, how certain trends might be shifting given the different operating environment producers are in, in terms of either volume or your supply costs, et cetera?

Well, we have - we will have more volumes that we have contracted year over year. And again, part of that is because we have more fractionation capacity at KFS with our second fractionator that is coming on.

And the new contract year starts in April. It goes from April to April.

Overall, we believe that we are very competitive with our supply costs. Then, part of that is because, again with our condensate system, we do have the condensate system or the hub for the industry, which most of the barrels are traded on; so most barrels end up on our system.

We have the largest demand for butane because of our - it feeds off our iso-octane facility. So with that I think we’re able to pass on the great value and - to our customers in terms of the prices that we purchased their butane at.

And propane, we have a rail facility and a marketing team that can access markets across North America. So I’m not sure if this year will be any different than any other years in terms of how competitive we are with our supply cost.

Okay. That’s very helpful, and just a clean-up question on the quarter.

Alberta Envirofuels, what was the nature of the unplanned outage, and what was the kind of financial impact?

I didn’t quite catch the last part. So you asked me what the financial impact was.

Again, we don’t provide that sort of detail. But what I can say is that, there are actually a few different maintenance items that were unrelated.

And I think we’ve concluded that most of them are sort of one-off type items. I would say that, we have a very experienced team that operates that facility.

It operated at capacity of 95% on average throughout 2015. So we did have a very, very good track-record of strong run times.

And just so happened in the first quarter, we had a few incidents that reduced our run-time in that quarter. And again, they’re more related to one-off sort of items.

It is sort of a complex facility, so that does happen from time-to-time. And we have confidence that we will run - have fairly good run times, I guess, into September, when we have our four-year turnaround schedule.

Okay, so 95% would be a good long-term run rate to you?

Yes, I mean, I can’t provide guidance on there. I mean, there’s no certainly that we wouldn’t have more.

But, I guess, at this point we have no indications that we have anything significant that would prevent us from operating at that facility fairly reliably until the turnaround in September.

Great, thank you.

Linda, I can add that our target is actually to be over a 100%, which we have achieved for periods of time. But you can never predict what kind of unplanned maintenance issues might crop up.

Okay. Thank you.

Good morning, everyone. So just looking at your spending requirements for the year and then considering your volume outlook and the turnaround at AEF, do you foresee any concerns or any scenarios where you might sort of bump up to your 3.5 times debt to EBITDA threshold throughout the year?

This is Steven speaking here. No, we don’t expect anything getting that close to our 4 times covenant ratio.

So we were quite pleased with the 2.4 times we had at the March 31. With that said, we always monitor our EBITDA, our capital finding, and how that comes in.

As well, we’re always continuing to monitor acquisition opportunities. With all that in mind, we keep an eye on all our funding alternatives.

Okay. And then just on your Williams pipeline acquisition, can you give some color on the return profile?

I believe approximated [ph] it’s kind of within your targeted range. I think your target was at 50% on leverage there, longer-term?

Yes, we don’t provide sort of details on our return expectations. We do believe it’s a very strategic investment.

It is in the largest energy hub in North America, which is in that Mont Belvieu area. It is connected to our Hull Terminal, as I mentioned earlier, and so the pipeline basically originates in the Beaumont area to the petrochemical and refine complex there, connects to our Hull facility.

And again, our Hull facility has 20,000 barrels a day of real capacity. We have six blocks for truck offload and also load, and we also have some storage vessels there as well.

So if we have our facility right now at Hull that is very well situated. And we’re not fully utilizing the capacity there.

So we do believe we can generate more income, both at the Hull Terminal with these new pipelines. And again, the pipeline also extends from Hull to the Mont Belvieu energy complex there.

Okay. Thank you very much.

Hi, I’d like to follow up on that discussion on the pipeline again. I think I heard from the comments that the pipeline can move spec-product as well as NGL mix.

So I was wondering if you could identify the spec-product. In particular, I’d like to know if it’s iso-octane?

And then, as a follow-up, what other tools do you need to enhance your position there and execute your strategy? I’m thinking storage and fractionation.

Do you need any significant investments of that nature?

Well, the - first of all, the spec-product that we’re talking about is butane, isobutane, propane, and NGL mix. So we believe that we can handle all four products with this pipeline.

With respect to storage, we do have contracted storage in the area that’s pipeline connected to our Hull Terminal, at an area called Daisetta, which is very close to our property. And we’re currently using that storage right now even though these pipelines are commissioned.

So we use it as part of our Hull operations today. And in terms of fractionation, it’s part of the commercial discussions that we’re having with some of the fractionation owners in the area.

And we certainly believe that we’ll be successful in contractually arranging for capacity at existing fractionation facilities that have - that are running live today. So we don’t believe that we need to fill - to build our own fractionation there.

There’s a lot of unutilized capacity, and we believe that we can contract it at an attractive rate.

Okay. That is helpful.

And two more related questions there, I just wondered if you can outline maybe what other opportunities you see that enhance your existing U.S. assets.

And then, in addition, comment as to whether or not Keyera has an appetite for a step-out acquisition in the U.S.?

I might take that question, Rob, it’s Dave Smith, here. First of all, I think, you were pretty excited about the potential that the Hull site has - I characterize it is kind of a long-term project.

We’re pleased with the business that we’ve been able to do there so far. I think the pipeline that we’ve acquired will be a tremendous additional asset that allows us to tie into Beaumont and Belvieu in a much more effective way.

But as we’ve indicated, we don’t expect that pipeline to be in service until 2018. So it’s kind of long-term project, but I think our vision for that site is pretty exciting.

We’ve got 270 acres, something like that, for further expansion. But it’s really going to depend on how the nature of the business evolves and the commercial arrangements that we can put in place.

With respect to other assets, I think we certainly would look to similar kinds of assets that would extend our NGL value chain. In the past, we’ve faced competition from U.S.

MLPs that have been quite aggressive in bidding for business and bidding for acquisitions, I think that’s changed a little bit now. So we have our eye out for the kinds of terminal storage facilities and pipelines that would be a logical extension of our NGL value chain.

But we’re going to be disciplined about what makes sense and what fits in well with the core competencies that we have.

Okay. Thanks very much for answering that question.

Thank you, good morning. Maybe a bigger, broader question on just your thoughts and feelings about Western Canadian gas relative to other basins in North America?

And I ask the question in part, because when you see TransCanada being in the midst of a fairly large M&A transaction with Columbia, which is really a big step out of their own and maybe a bit of a reinvention, how does that make you feel about the relative competitiveness and positioning about the basin in Western Canada?

Andrew, it’s Dave Smith again. I will take a shot at that one.

It’s certainly something that we monitor very carefully. We believe - and I’ve actually seen some very interesting stats recently that would suggest that many of the zones that are characteristic of the Western Canada Sedimentary Basin are very competitive with the resource plays that you see throughout the U.S.

The benefit that we have in Western Canada is the diversity of the geology, the stacked geology that sits underneath many of our gathering and processing facilities in the western part of the basin. And when you look at the economics associated with some of the Spirit River zones, like, the Falher, and the Wilrich, and the Notikewin, the Glauconite.

When you look at the Montney, when you look at the Duvernay, these are all zones that from an economic point of view are very competitive with many of the resource plays in the U.S. that you hear about.

Of course, the challenge for us as an industry is that we’re a little bit further away from some of the bigger markets in places, like, the Midwest and the U.S. Northeast.

And so we need to solve the market access and transportation challenges that we face as an industry. And in the near-term here, we’ve seen the basis differential between AECO and NYMEX get quite wide - disappointingly wide, I would say.

But I think from the long-term point of view, we’re still very optimistic. I believe that we’re going to see significant growth in North American demand for natural gas, and I believe the Western Canadian basin will be in a great position to be able to serve that demand.

And the other thing that we would love to see, of course, is a couple of LNG projects on the West Coast that would allow the industry to access markets for natural gas elsewhere in the world. So I’m cautiously - I’m cautious about the near-term outlook, but I’m very optimistic about the long-term outlook.

Okay. That’s very helpful color.

And then maybe a second question to Steven. Just on the quarter - if I look year-over-year you had effectively operating margin expansion.

And it’s obviously a very difficult environment right now for the energy complex. And so, what were the key factors driving that expansion in your business lines?

Well, it would be - it’s right in the earlier comments that we were able to keep approximately [$80 million of something] [ph] EBITDA coming through on various projects. So it would have been spread over both energy sector as well as in the downstream [ph] side of it, galvanizer [ph] the rail terminal that came on the hillside [indiscernible] sometime at the [indiscernible] place as well.

So it’s really just to bringing on of various projects throughout the year that help bring on the operating margin. But as we noted, we did have some non-recurring costs in terms of having write-off a couple of the project studies.

I think one was on the sulfur project. That was the bulk of it, and which [indiscernible] finding probability, that project moves forward.

That being said, we’re still always trying to talk and we find out ways of structures and those kinds of projects as well. I should say the cash taxes as well as one - is one key thing as well that helps, again the full cash flow.

Again, mirrored on top of all this was the extraordinary gains we had in Q1 of 2016 [ph] really related to the [indiscernible] write-down of these [indiscernible].

Okay. That’s helpful.

Thank you.

Good morning and thank you. You had a $6 million write down in G&A on projects that you don’t expect to proceed.

Which projects are written down? And do you expect further charges of this nature?

Sorry, I was trying to fix my mic. It sounds like I’m breaking up a little bit.

What was that question again?

You had a $6 million write down in G&A on projects you don’t expect to proceed. Which projects are written down?

And do you expect further charges like this?

Yes. Just to clarify, it’s more the fact that when we have a very high probability project we generally capitalize those study costs or development costs.

And when we get to a decision, as I mentioned with the Suncor sulfur project, we just thought the probability wasn’t high enough to justify keeping that as a capitalized item. So we reclassified it as an expense item, that’s really with that is.

On a go-forward basis, we don’t see really anything else material that would fall into that bucket.

Thank you, Steven. It appears that Keyera has about $500 million already invested in assets under construction, including KFS fractionator, and about $1.5 billion in approved projects.

So should we be thinking that you’ll have another $1 billion in gross capital investment between now and mid-2018?

Yes. I think that’s - I don’t have the numbers right in front of me, we can always come back to you on that.

But we’re still targeting $600 million this year, and I believe that still moves into sort of $300 million to $400 million related to those projects for 2017. On top of that, we still always have our ongoing storage cavern developments, the projects around Hull, et cetera.

So I don’t see any issue at all seeing that kind of a number go forward.

Thank you. Those are my questions.

Good morning. I just wanted to come back to the Texas Pipe acquisition, and I’m just wondering how many other pipeline connections or commercial agreements you need to have in place?

How complex is this going to be? You touched on fractionation.

I’m just wondering what else you might be looking at?

Robert, it’s Dean. And right now, we’re just focused on making sure that we are connected to other lines that will get us into the fractionation.

And really, once we get into Mont Belvieu and we get connected into another line there that will take us right into to - tie into fractionation, also additional storage there. Really once you get into that area you can basically get to water, you can get to other pet chem facilities.

So some of the barrels aren’t even physically moved, they are traded. So it is the largest hub in North America, so it’s just an incredibly liquid environment in terms of transacting barrels.

So right now, we are just making sure that we get the pipeline connected so we can hit the frac and storage basically in the Mont Belvieu area, and that will connect us to the rest of the market.

Okay. And so you’ve talked a lot about the Hull to Belvieu portion.

I’m just wondering how are you thinking about the line that runs right now from Belmont into Hull? Is that something that could be reversed?

I don’t know if there’s access to a port there? Does it - for example, if there is, does that allow you to maybe let go of the storage that you’re leasing in Galena Park?

We like the storage at Galena Park for our iso-octane business. But going back to your other question about Beaumont, we have a lot of options.

I think the commercial arrangements and something that we could at least, probably, show in a few months once those negotiations are complete. But if you look on a map of where this pipeline resides, there’s a whole bunch of other pipelines that sort of crisscross it.

So the tie-ins are very, very short in terms of what we’d have to do to connect to other lines to get us right into Mont Belvieu. And in terms of Beaumont, we might use the pipeline to go to Beaumont, or we might use it to have another line go into Mont Belvieu, because it does cross other lines that go in that direction.

Okay. That’s great.

From the - just maybe to Alberta and the petrochemical diversification program - I’m just wondering if you got any additional thoughts on that? And were you part of any submissions that went into that?

No, we weren’t. The first round was related to propane and methane specifically.

I am involved with the Resource Diversification Council, and we are working with governments in terms of helping the province diversify and basically upgrade our natural resources in our province. And so there is a potential for more programs in the future, but at this point we’ve only announced the initial one, which is propane and methane.

And now we should focus on the processes.

Okay. And if I can ask one last question - you mentioned in the MD&A that your rail cars went up just by taking on additional cars, but that you expect some of that to be used when the KFS frac expansion comes online.

I’m just wondering, do you expect all of that excess capacity to be used? Or is it just going to be a portion based what you’re seeing in terms of general market dynamics right now?

Well, first of all, I’d just comment that, with regard to rail cars, we need to send our made [ph] so way in advance. So we’re talking 15 months in advance.

The lead time on them are very long, so you’re trying to predict what your needs are in the future. So we did commit to these cars back in 2014.

We will be utilizing more of the cars once our second frac comes online next month. We will utilize - and we did incur some initial cars to basically take possession of these cars, because you basically have to put these cars into storage until you use them, and you’re not moving any products when you first take possession of them.

So those costs will be basically borne as a company. What I also can say is that - so we will use more of the cars.

If we don’t happen to use all of them, we have our leases basically staged so that we can elect not to renew them and reduce our fleet over time if we decided that we actually don’t need that many cars. Right now, we have about 2,450 cars in our fleet.

Okay, that’s great. Thanks very much.

Good morning. Wanted to come back to some of the contract renegotiations underway.

You are currently working with a customer at Rimbey. Can you comment on some of your other core G&P assets?

And whether or not you expect pressure on those fees as well in order to keep volumes at the plants? And then maybe as an offset, how much more room you might have on the op cost front to perhaps keep margins flat going forward?

Patrick, this is Brad here. I think we continue to work with all of our customers at all of our plants to provide them optionality on their fees when they come under pressure.

I think it happens in a number of different facilities. A lot of the driver behind that is how much infrastructure they need to go through in order to get to your plant.

Sometimes they have to go through multiple compressors to get into a gas plant, so consequently when you layer on all the way back it can be a little bit onerous on the producer. So we’ll look at scenarios like that and try to rationalize that.

Again, taking a bit of a long-term view that if we can provide some short-term relief for some long-term optionality for both us and the producers, then that’s a win-win for both of us. On the operating cost side, I think we’re pleased with the results we’ve achieved to date.

We began an aggressive project here late in 2015, early 2016, and we’ve been pleased at what we’ve been able to achieve to date. That being said, the work there is never done.

We continue to look at our cost structure, continue to look for opportunities to improve our operations to reduce our operating costs, whether it be utilities or service costs or other things like that, and where we can provide that benefit back to the producer. So I think it’s an ongoing effort that we’re going to continue to work on through 2016.

It’s hard to say what the overall goals could be, but I think we’re pleased with what we’ve been able to achieve to date.

Okay. Thanks for that, Brad.

And also, did you mention earlier, or can you say, which plants you expect to be impacted by the TCPL maintenance in the second and third quarters?

It’s very hard to say. TransCanada publishes a maintenance program where you can see work that they’ve got going on, on our system.

You have to correlate that with the current loads on the system to determine what the overall impact is going to be. I think we’ve been pleased so far this year that even though some of this maintenance work has begun already, the impacts on our world have been relatively small.

So we’re hoping that, that’s going to continue through 2016. But it’s hard to predict.

Like our world, there’s planned maintenance and there’s unplanned maintenance that will impact, both.

Okay. Got it.

And lastly, just with respect to construction costs coming in under budget - can you just confirm if - and perhaps for David - if you’re able to keep 100% of those cost savings or should we expect some sharing with customers, and perhaps a little bit less EBITDA kicking off those projects going forward? Thanks.

Obviously, it depends. Each project is a little different in terms of the commercial terms, Pat.

But I think in terms of the major projects that we have currently under way, there are no adjustors in fees. I can get back to you and confirm that, but I believe that those capital cost savings on the projects that I’m thinking of would - we’d be able to keep, basically.

Okay, great. Thanks, guys.

That’s all I had.

Hi, good morning. I had two quick questions if I may, please.

Just wanted to know if there’s any kind of indication about startup of the Cheecham Terminal, please?

Sorry. I’ll take that one.

I think, we’re waiting, I think every indication is that things are starting to - the projects up there are starting to get restarted. My understanding this morning is that the highway through Fort McMurray has been reopened for industrial traffic to allow some of the oil sands projects to get the equipment in that they need to restart.

So it’s my expectation that we will get the green light to go back to South Cheecham at some time in the next few days. But at this point we just don’t know.

Okay. And what is the current capacity of that terminal, please?

We’re drawing a blank here, so we’ll have to get back to you on that question.

No worries. And very quickly, I wanted to ask you - with regards to the Alberta Crude Terminal, what kind of utilization rates did you have in Q1, please?

We don’t provide that sort of detailed information. What I can say is that it’s certainly less than what it was last year.

And part of that is because some of the rail traffic is actually getting offloaded in the Chicago area, and it’s coming into Alberta on one of the long haul pipes being coached into our southern lines. So we do believe that condensate or diluent demand is going to continue to increase over the next two or three years as more oil sands projects come online and that bitumen production increases.

So we do believe over time that that demand for our rail service should increase, too.

Right. Sorry, I should have been more explicit.

I was talking about the crude terminal that’s the - was the refinery in Brunswick?

Sorry. In terms of the crude terminal, we do have a take-or-pay contract with Irving Oil on that contract.

It’s a long-term contract. Right now, just our cash flow is secure on there.

Their volumes do vary from month to month depending on the economics from them. But generally the barrels moving out of Western Canada aren’t quite as advantaged as they used to be, and that’s because of the lifting of the ban on - or the restrictions on exporting crude oil out of the United States.

So once that’s done, it’s basically reduced the arb between the WTI and Brent. So because of the difference between WTI and Brent is a lot tighter these days, the barrels out of Western Canada aren’t as cheap relative to the Brent barrels that they can access on the water.

Okay, all right. Thank you very much.

Hello. Thanks, this is Leah on for Ben Pham.

My first question was on the producer shut-in. Are you really expecting more throughout the year?

Or is the 2% level we saw in the first quarter - is that pretty fair?

Leah, this is Brad. I think we continue to monitor that.

Certainly, the softer the commodity prices, the more pressure is going to be put on producers. But as I’ve said previously, we continue to work with all the producers to see if we can find solutions in cases where their margins are constrained and give them optionality to preserve those volumes.

So it’s hard to say what the future is going to hold, but I think we certainly have some flexibility in our world to help them out. And if we can do that, it’s just as well.

Okay. Thanks.

And then I just had another question on CapEx, you guys narrowed it down to $600 million at the bottom end of your previous range. And so this kind of narrowing - was it entirely cost savings and reductions?

Or was there something else on that?

It’s a combination of a few different things. One being the lower costs that we’re seeing on the larger projects.

But as well just continuing to look at the project timing and schedules for the various projects. All relatively in-line, but they do flow through and just sort of tightening it up.

As well, when we look at that range, $600 million to $700 million, that had a little bit more probability waiting for some probable projects. And now that we’re in May, for this year we don’t think some of those will necessarily materialize and hit time-wise into this year, necessarily.

Great. Thanks.

That’s all for me.

Operator, I have an answer to Ashok’s earlier question with respect to the capacity of the South Cheecham Rail Terminal. Between rail loading and rail offloading, it’s approximately 39,000 barrels a day.

And at this point, I would like to thank everyone for listening to our 2016 first quarter conference call. If you have any other questions you can reply back to the investor relations group.

Thanks for listening, and have a great day.