Lavonne Zdunich - Director, IR David Smith - President and CEO Steven Kroeker - SVP and CFO Brad Lock - SVP, Gathering and Processing Business Unit Dean Setoguchi - SVP, Liquids Business Unit

David Galison - Canaccord Genuity David Noseworthy - Macquarie Linda Ezergailis - TD Securities Ben Pham - BMO Rob Hope - Scotiabank Robert Catellier - CIBC Capital Markets Robert Kwan - RBC Capital Markets

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

With me today is David Smith, the President and CEO; Steven Kroeker, Senior Vice President and CFO; Brad Lock, Senior Vice President, Gathering and Processing Business Unit; and Dean Setoguchi, Senior Vice President of the Liquids Business Unit. In a moment, David will provide an overview of the quarter, followed by an operational update from Brad and Dean.

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

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 general economic, market and business conditions; fluctuations in supply/demand, inventory levels and pricings of natural gas, NGLs, isooctane and crude oil; the activities of producers and other industry players, including our joint venture partners and customers; our operating and other costs; the availability and cost 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 2017 third quarter report that was 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. Yesterday we reported our third quarter financial results and I am pleased with how Keyera has been able to leverage our assets, expertise and reputation to provide efficient and effective midstream solutions to producers, resulting in steady financial results quarter over quarter.

Net earnings were $38 million for the third quarter of 2017. Adjusted EBITDA was $138 million, and distributable cash flow was $108 million.

Keyera maintained one of the lowest payout ratios in the Canadian midstream peer group at 73% for the quarter and 69% year to date. Both our Gathering and Processing Business Unit and our Liquids Infrastructure segment generated increased cash flow over the previous quarter.

The Gathering and Processing results were supported by higher overall throughput compared to the previous quarter. The Liquids Infrastructure segment reported record results for the fifth consecutive quarter as we continued to grow our asset base and service offerings.

Our Alberta EnviroFuels facility performed very well during the quarter, achieving excellent run rates. As expected, the Marketing results were affected by the seasonality of our propane marketing.

Significantly higher realized margins are forecasted for the next two quarters, as our propane inventory is sold into the North American market during the winter. Steven will speak more about our financial results later in the call.

Despite the challenging environment we continued to strengthen our foundation and pursue the right opportunities to increase shareholder value. We continue to focus on maximizing utilization at our current facilities, increasing our presence in the liquids-rich Montney and Duvernay development regions, enhancing our condensate network and services and expanding our storage facilities.

Supporting our strategic direction we recently entered into a long-term midstream agreement with Chevron Canada Limited to fractionate and handle 50% of their natural gas liquids from their Kaybob Duvernay operations. Yesterday we announced our North Wapiti Pipeline System, which will extend the capture area of our Wapiti gas plant currently under construction to the area north of the Wapiti River in support of Montney producers in that region.

With that project, we plan to invest between 700 million and 800 million in 2018. With that introduction, Brad Lock will now discuss our Gathering and Processing Business Unit.

Thanks, David. The Gathering and Processing Business Unit delivered an operating margin of CAD 69 million and processed gross throughput volumes of almost 1.5 billion cubic feet per day in the third quarter of 2017, 2% higher than the previous quarter and 8% higher than the same quarter last year.

A large portion of the increase was attributable to the Simonette gas plant that achieved record average throughput volumes for the third quarter despite the facility being offline for a 17-day maintenance turnaround during the month of August. The continued growth in volumes at Simonette is a result of strong producer activity in the Montney and Duvernay geological zones.

To support this activity, as David mentioned, we announced our plans to construct the North Wapati Pipeline System, which will further extend the capture area of our Wapati gas plant that is currently under construction. The North Wapati Pipeline will extend from our Wapati gas plant to lands north of the Wapati, making Keyera an early mover into this area that includes the Montney zone in the Pipestone development area.

The North Wapati Pipeline System includes gas and liquid pipelines and a central compression and dehydration facility north of the river. Based on current estimates, the system is expected to cost approximately CAD 120 million and is expected to be in service in the second half of 2019, subject to route finalization and regulatory approvals.

Privately owned Pipestone Oil Corporation has underpinned the pipeline project with a long-term take-or-pay natural gas gathering and processing arrangement. We expect these contracted volumes will provide the foundation for Keyera to sanction the second phase of our Wapati gas plant in the future, as we continue to align our plans with the producer’s development plans.

Keyera remains committed to working with our gathering and processing customers to deliver cost-effective and value-added services that enhance their economics. During the quarter we completed a successful turnaround at Simonette that was finished ahead of schedule and on budget.

In 2018 we have decided to modify our Strachan gas plant to increase efficiencies and reduce operating costs of the plant by shutting down our sour processing and sulfur-handling equipment and converting the plant exclusively to a sweet-gas-processing facility. This project will coincide to a Strachan’s planned maintenance turnaround in mid-2018.

Other maintenance turnarounds planned are at our Nevis and Brazeau North gas plants in 2018. The combined costs of all three turnarounds is expected to be around CAD$26 million.

I will now turn it over to Dean to discuss the Liquids Business Unit.

Thanks, Brad. Operating margin for the Liquids Infrastructure segment was a record CAD$72 million, as demand for our condensate services continued to increase.

The remaining Fort Hills take-or-pay contracts on Norlite came into effect and incremental fractionation volumes were processed. At our Fort Saskatchewan fractionation facility, utilization increased 21% since the beginning of the year and was at 97% for the third quarter.

Over the last three months construction advanced on a number of our capital projects. To enhance our condensate network we completed 4 60,000-barrel condensate storage tanks at our Edmonton terminal.

These tanks enhance Keyera’s ability to deliver diluent to the oil sands in a reliable, cost-effective manner. Construction continued on the South Grand Rapids Pipeline, which is now expected to be completed in mid-2018.

This pipeline will provide additional condensate capacity between Edmonton and Fort Saskatchewan to satisfy contracted volumes on our condensate network and support growing diluent needs of oil sands producers. We expect the Base Line crude oil storage project in Edmonton to be completed in stages throughout 2018, with the first four tanks ready for commercial use early next year.

The project is a 50-50 joint venture with Kinder Morgan that is fully contracted with take-or-pay contracts up to 10 years in length. We also continue to expand our underground NGL storage facility at Fort Saskatchewan.

We’re currently washing three additional caverns and expect to have one in service in the first half of 2018, adding to our current gross cavern capacity of 13 million barrels. Also adding to our growth in 2018 will be our Keylink NGL pipeline system.

During the quarter we received the final regulatory approvals for the new pipeline segments to be constructed. Upon completion this pipeline system will connect eight of our gas plants, provide customers with a safe, reliable and economically beneficial transportation alternative to trucks and rail.

Looking even further ahead, our 20-year midstream agreement with Chevron to support their Kaybob Duvernay operations represents a great opportunity for Keyera. While we initially expect to provide their requested services at our Fort Saskatchewan energy complex, depending on the success and scale of the Chevron Duvernay program we may need to expand these facilities in the future.

Chevron recently announced that it is moving ahead with this development and has executed further service agreements with Keyera to fractionate 50% of their NGLs. Turning to the Marketing segment, third quarter isooctane sales were strong as production averaged above nameplate capacity.

Since completing its necessary work earlier this year, our Alberta EnviroFuels facility has been operating very well. Our third quarter results were affected by the seasonality of our propane marketing.

Realized margin for marketing for the third quarter was CAD$10 million, but included CAD$23 million in realized cash losses, primarily related to risk management contracts that were put in place to protect the value of propane inventory. Realized losses occurred as propane prices increased based -- through the third quarter and rolling monthly hedges were settled.

We expect to realize on strong physical margins as the inventory is sold in the fourth quarter of 2017 and first quarter of 2018. With that, I’ll turn it over to Steven to discuss the financial results in more detail.

Thanks, Dean. As mentioned earlier, we reported a solid quarter even in this challenging environment of continued low commodity prices and pipeline curtailments.

Our integrated fee-for-service business continues to deliver steady results, with fee-for-service operating margin reaching 141 million for the quarter versus 135 million for the third quarter of 2016. And while our propane strategy has resulted in greater seasonal variability in our Marketing segment, it has enabled us to attract incremental volumes through our fractionation facility.

Realized margin for the quarter was 154 million, 17 million lower than in the third quarter of 2016. As a reminder, realized margin excludes unrealized gains and losses related to the Marketing segment.

The primary reason for the decrease in our realized margin related to our propane strategy, as Dean discussed earlier. This contributed to the Marketing segment’s realized margin being 23 million lower than the same quarter last year.

Keyera’s realized margin for the third quarter of 2017 did benefit from a 14% increase in operating margin for the Liquids Infrastructure segment, or $9 million, compared to the third quarter of 2016. Meanwhile, the Gathering and Processing segment’s operating margin of 69 million for the third quarter of 2017 was about 4% lower than the third quarter of 2016.

Adjusted EBITDA was 138 million, 10 million less than the same quarter last year due to the lower realized margin and higher general and administrative costs, partially offset by 7 million in lower long-term incentive plan costs. These same factors affected net earnings for the third quarter, which was 38 million, or 14 million lower than the same period last year.

Distributable cash flow was 108 million, or 7 million higher than the same quarter last year. This was primarily due to lower maintenance capital, as the third quarter of 2016 included AEF turnaround costs.

Our growth capital program for 2017 is now expected to range between 700 million and 750 million, as the acquisition of 50% of the South Grand Rapids diluent pipeline will now be completed in mid-2018 when the pipeline is expected to come into service. Based on current plans, we expect our 2018 growth capital program to range between 700 million and 800 million.

This capital range largely involves projects currently underway, such as the Base Line Tank Terminal, the Keylink NGL pipeline system, the Wapati gas plant and the Simonette gas plant liquids handling expansion. This estimate also includes the new North Wapati Pipeline project, along with the acquisition of the South Grand Rapids diluent pipeline.

Maintenance capital for 2018 is expected to range between 40 million and 50 million and includes the scheduled turnarounds at Strachan, Nevis and Brazeau North. Cash taxes for 2018 are expected to range between 45 million and 55 million and are based on expected taxable income in 2017, since Keyera uses a deferred partnership structure.

The cash taxes also reflect Keyera’s use of capital cost allowance deductions. Our tax pools are estimated at approximately 2.2 billion at September 30 of 2017.

Finally, Keyera continues to have one of the strongest balance sheets amongst our peer group, with a net-debt-to-EBITDA ratio of 3.15 times at the end of the third quarter. During the quarter we closed our $400 million, 3.68% 10 year private note offering.

As well, we were recently assigned two solid investment-grade credit ratings. DBRS assigned Keyera an issuer rating of BBB with a stable trend, and S&P Global assigned Keyera a long-term corporate credit rating of BBB stable.

With these credit ratings, Keyera now has additional flexibility in funding its capital programs and potential acquisitions. That concludes my remarks.

David?

Thank you, Steven. We are pleased with the performance of Keyera’s base business and the growing contribution from the capital projects that we have brought online over the last couple of years.

Overall, the team is looking forward to a strong finish to 2017 and we are optimistic about our future prospects as the industry recovers. We remain focused on building shareholder value, while balancing risk.

Thank you to all of our employees, customers, shareholders and other stakeholders for their continued support. With that, I’ll turn it back over to the operator.

Please go ahead with questions.

So my first question would be on the Marketing segment and the margins there. Now, you indicated that you’re expecting the margins to improve significantly over the next couple of quarters.

Just wondering if you could give a little more color. Is it going to be just up, you know, up significantly from a low base or above, like more normalized levels?

We did provide a guidance statement in the Q3 release as well, which basically repeated what we said in Q2, which basically said we believe the realized margins from Marketing will be lower than last year’s results. Again, that was about CAD 137 million last year.

Obviously we had the chance and opportunity to revise that statement, but we thought that was still an appropriate statement to use. So we really do believe that we expect significantly higher margins in Q4 and Q1 with respect to that.

And that’s why we were comfortable putting that statement back into the quarter.

Okay. And just my next question is you essentially have had the challenges over the last couple of quarters with isooctane as well.

The debt to EBITDA has been sort of inching up. Just wondering; are you comfortable with your outlook going forward because you’re getting close to your internal target of 3.5 times?

Well, historically we try to operate in that 2.5 to 3 times range. We think that’s a prudent range.

I think we’ve demonstrated a pretty consistent track record of approaching our balance sheet from a prudent perspective. Again, we take a little bit more or a longer-term look at debt-to-EBITDA ratios, keeping in mind what we expect for EBITDA in the future as well.

And so at 3.15, we definitely think it’s a manageable ratio. But that being said, we’re always trying to monitor that and continue to manage our balance sheet.

Okay. And then just a quick maintenance question.

Could you remind me how much the acquisition for the South Grand Rapids diluent pipeline is in that 2018 CapEx guidance?

I may not have the exact number, but it’s approximately 120 million. So I think -- once TransCanada has finished constructing that and the pipeline’s in service, then we will acquire 50% of their interest in the pipeline.

Perhaps I can just start on the guidance a little bit more. In terms of what drove the delay in the South Grand Rapids Pipeline, can you just give us a little color, given it was only August when you kind of added that to your CapEx guidance for 2017?

The delay is just associated just getting the line fully connected into Edmonton. So it’s not going to drive costs higher or anything like that.

It’s a delay and, again, we’ll acquire the pipeline when it’s completed.

David, this is David Smith here. I would add to that that the pipe itself, you know, it’s kind of the last mile that’s the most tricky.

And the pipe itself is finished. It’s just that with the number of other activities going on at our Keyera Edmonton terminal and with the Baseline tank terminal it made sense to sequence the conclusion of the South Grand Rapids Pipeline appropriately along with those other activities.

As you know, the capacity in that pipeline is something that is in addition to the capacity in our condensate network between Edmonton and Fort Saskatchewan and we really don’t need that capacity in the near term. It’s only as volumes continue to grow that we start to require it.

So the delay in the estimated completion -- as Dean says, it has no impact on the cost and it also has no impact on our expected EBITDA.

Okay, thank you for that color. And then moving to 2018, is there any portion of that 700 million to 800 million that is kind of non-board-sanctioned projects, so like for example, Wapati phase 2 or some sort of capital related to the Chevron deal?

Or is it all 100% announced sanctioned projects?

Substantially all of that range is basically accounted for with approved projects, including the South Grand Rapids acquisition and the Wapati pipeline project. There are various capital expenditures around the Wapati gas plant in the phase 1 there, etcetera, that again have to be tackled and spent this year.

Okay, and then maybe one last question on the guidance. Just with regards to your tax guidance, given the significant number of growth projects you have coming online both in ‘17 and ‘18, I imagine, you know your $2.2 billion tax pools already and growing.

Yet, your cash guidance for 2018 is up materially year-over-year on a modest increase in earnings before taxes. Can you provide a bit more color on what’s driving that and how we should think about it going forward?

Again, the cash tax guidance, the reason we were able to have a bit more view on that is that it’s based on -- like, next year’s tax guidance is based on this year’s expected view on taxable income. So, again, we expect a strong fourth quarter on our marketing side in that respect there.

The thing to remember about capital expenditures is that you can’t access those tax pools until those assets are available for use. And so several projects are still not in available-for-use mode yet.

Something like a Norlite pipeline would be, but that would be a lower CCA rate, more in the pipeline type of rate. And so that gives you a little bit of color on that.

And I would also comment that for given the size of our company and the EBITDA that we generate, the 5 million to 10 million for ‘17 would be the more -- I was going to say abnormal, but we benefited from a low cash tax in ‘17 because of the high claim rate pools we had on our previous projects like the fractionaters, which have very attractive CCA rates.

Okay, appreciate that color. Last question.

Can you comment on the decision why now to seek a corporate credit rating? What is it about the public markets?

You’ve always depended on the private debt markets for that debt financing, never had an issue with it [indiscernible]. What’s changed?

Well, we continue to see, as you saw in the Q3 release, a continued robust capital program. We continue to see acquisitions out there as well, opportunities.

And so we were just at a point now that it was important to continue to maximize the flexibility of our funding sources. And so with that was investment-grade credit ratings.

That does give us access to public debt. It does give us access to equity instruments like preferred shares.

And so we’re happy to take that next step in our evolution there.

Congrats to the finance team for getting those debt ratings. It’s probably a lot of work.

I’m just wondering how that might affect a number of considerations in your financing plans. Specifically, might that affect how quickly you choose to term out your -- or increase the duration of any sort of financing of longer-dated projects, realizing there might be some dilution or drag on the balance sheet if you’re issuing pref sooner.

How are you thinking about your capacity on your balance sheet for pref and hybrid securities? And, given your robust CapEx program, what sort of current capacity do you see having on your balance sheet to add to that before you need to maybe issue common equity.

Okay, I’ll try and remember those questions in that order. Terming out -- well, we’ve been very successful, I believe, in the private note markets accessing quite long-term debt.

So I believe from a terming out of debt and matching up with projects that we’ve been securing, we’ve done a pretty good job on that. So there’s no immediate need to do any additional terming out in that respect I don’t think.

And, again, the rates have been competitive and so we’ve been happy with that. As well with the 400 million of proceeds that came in September, that did substantially bring down our revolver to that, just off the top of my head, 100 million kind of level back at September 30.

So, again, we’re happy with that capacity and that flexibility we have on the revolver. In terms of capacity for prefs and those kinds of instruments, obviously there is room for that within the balance sheet structure.

A lot of times people use 10% to 15% of their capital structure being allocated towards those kinds of instruments, and so with a CAD 9 billion enterprise value that does give us room on that side. That being said, we are aware that you don’t get as much equity treatment for those kinds of securities.

And so, again, it will be just a continued balancing act as you look at your equity options as we go forward and look at funding. So, again, we approach things from a prudent perspective.

I think it is fair to say that in the future you will see us tap into those types of markets if it makes sense -- and, again, happy to do that. From a leverage ratio and capacity point of view on common equity, again, the current multiple is a manageable multiple.

And from our point of view we just continue to look at that quarter by quarter and look into the future as well in terms of EBITDA expectations and capital requirements. And so we’re just going to try and continue to keep all our options available in terms of looking at funding.

And for your current base plan, do you have a DRIP on to the end of 2018?

Yes, we do. And so both programs of the DRIP program will be in there.

And I believe it’s about CAD$180 million a year in terms of proceeds there. And we believe with our robust capital program that we -- it’s still prudent to do that.

And maybe just more of an operational question. What might be the bookends of timing of when Keyera might sanction the second phase of the Wapati gas plant?

And what’s the thinking on the likely size and cost of that at this point? And I guess my third prong of my question might be is there the land and the potential demand for a third phase down the road.

Linda, this is Brad. I think certainly we’re optimistic that we would reach a sanctioning decision for Wapati phase 2 in 2018.

We’re going to line our capital expenditures with the producer’s development plan so that we get capacity when it’s needed for the market and not get too far ahead of it. Capacity-wise, we completed the engineering for another 150-million-a-day train when we sanction the first train.

All of that is going to have to be re-dusted off and revalidated before we sanction. So that work is going to start right away to revalidate the cost estimate.

But the guidance that we had given when we built the entire Wapati build-out was CAD$625 million, which basically added another CAD$150 million of capital in there for the next tranches of investment. I think in terms of future development, I think we’re going to, as always, take a prudent approach to figuring out where the next tranches of capacity are going to come, whether they make sense at the existing Wapati plant or some other location.

But I think those thought processes we’re already thinking about in terms of where the next piece of capacity would land and whether the existing Wapati site or another site might be more appropriate, given where development plans look.

And as you optimize your system from a network perspective, might we see other initiatives in terms of shutting down sour gas processing anywhere else? Or is Strachan kind of a one-off?

And will there be any sort of asset write-down associated that potentially in mid-2018? I don’t know what the book value is.

I think we continue to look at sour gas processing, certainly in the central Alberta region. There’s not a lot of sour gas being drilled.

So consequently, continuing to manage your portfolio offering to the gas that’s being -- that needs processing is something that we’re going to do. You know, two years ago we shut down the sour processing at our West Pembina plant.

So this is kind of the next tranche and we continue to find the right places to land sour gas within our network. Fortunately, with our connectivity we can defer, push sour gas to other plants in many cases to ensure that that gas stays on and optimize our operating costs for that region.

As far as write-down, I don’t believe…

We’re not currently anticipating any more additional write-downs related to those issues.

A couple follow-up questions on Marketing and the outlook you’ve provided the next two quarters. I’m wondering to what extent is Keyera hedged over the next couple quarters on the propane marketing?

This is Dean. We are pretty well hedged for the winter months.

So most of our inventory would be hedged to match our winter sales. And I would say, starting on October 1 we move to a 24 hour shift at our Josephburg terminal.

And so for the last five or six weeks we’ve been railing out the physical product and realizing on the higher margins at the start of the winter season.

Okay. And as you’ve gone through Q2, Q3 and looking at Q4 and the new contract you put in and you kind of seen how things materialize, is the propane margins, the seasonal spread, I mean, do you anticipate that to be relatively in the same range as you look forward the next few years?

Or is it not something you’re really thinking about because you think conditions could change dramatically on the fractionation side?

I’ll maybe try this one, Ben. It’s David Smith here.

You know, it’s difficult to predict year-to-year, because the dynamics have changed a fair bit over the course of the last two or three years. We’ve gone through a period here where propane was very cheap in North America, just because we had so much more supply than demand.

What’s changed that in the last 12 months of course is that we’ve seen much greater volumes of exports. Most of those exports have gone out of the U.S.

Gulf Coast to the point now where North America is back into a supply-demand balance. And so part of the change in our strategy and our approach to the business is really just to kind of respond to that changing dynamic.

If I were asked to kind of predict for 2018 I would suggest it’s probably going to look much the same as 2017. There may be some additional NGL supply coming on as volumes grow in both Canada and the U.S., but at the same time we don’t see any reason why those exports would slow down.

And so I think we will be trying to be responsive to the seasonality of demand in North America and that probably means that we’re going to have a similar seasonal pattern in 2018 to what we saw in 2017. But we’ll have a much better sense for that come the end of Q1.

Okay. And I just wanted to check.

Would you say that the seasonal spread, it’s quite tight, that in this quarter you’re understating isooctane margins and perhaps that changes next quarter, but if margins were, let’s say, 20 instead of 10 this year, that 10 million more is offset as a hedge into Q4?

I’m not sure I understand the question, Ben.

I’m just wondering. It seems like Q3 you’re buying propane inventory and that’s understating the isooctane production.

But you’re getting a benefit of the propane lifting in Q4. But that’s largely a hedge between Q3, Q4 in terms of buying propane at X price this quarter and then next quarter you’re selling it.

But between Q3 and Q4 the seasonal spread on propane, it’s largely tight between the two.

The seasonality between Q3 and Q4 is almost entirely due to propane, for sure. And I think, as Steven was explaining, that was exacerbated by the fact that we had realized losses on some of the inventory hedges that we had in place in Q3, which we will in effect earn back in Q4 and Q1.

I think you were also asking about isooctane. And I think what I would say there is our production levels for isooctane were stronger than they’ve ever been in Q3.

The margins in 2017 have not been quite as strong as what we saw back in 2014 and 2015, but it’s still been a very good contributor to the Marketing segment.

And then on isooctane, Q4 generally is a softer quarter than Q3 for isooctane. So we had that in mind when we reiterated our guidance statement.

Ben, if you have more detailed questions, we can maybe take it -- you can give us a call. We can go through it in more detail.

All right. Thanks very much.

Maybe going back to some of Brad’s comments on adding capacity when and where it’s required, just want to get a sense of how you’re looking at Simonette. You’re almost butting up against capacity there.

Are you looking to potentially expand that project? Or could you network that into Wapati longer term as well?

It’s a great question, Rob. Actually, utilizing the Wapati pipeline and Simonette capacity and figuring out where to best land capacity certainly enters into our strategy.

I think we’re encouraged right now on how growth has -- volumes have grown at Simonette. And we’re always trying to stay ahead of our producer’s needs there.

So evaluating capacity at Simonette is certainly one of the things that we’re thinking about in our long-term growth through ‘18.

Okay. That’s helpful.

And then maybe going back to cash taxes, acknowledging that 5 million to 10 million is probably too low, but looking out at 2018 and I guess even further into 2019, assuming income does continue to move higher as new projects enter service, but looking out to 2019, you will also have some of the high CCA pools at Wapati and I guess Wapati North pipe as well, more so on Wapati. Is the expectation that the 2018 cash tax range is kind of, I would say, sustainable into 2019?

Or could you even see it come back down again?

Yes, that’s a good question. Again, from our point of view it’s a little bit hard to look that far out.

We have our forecast and expectations but we don’t generally give guidance that far out. But 50 million is probably a more sustainable level than 5 million this year or 5 million or 10 million, whatever we have this year.

And, again, it’s very dependent on the taxable income of -- for example, 2019’s cash tax is very dependent on the results in 2018 in terms of taxable income.

I was wondering if you could just discuss what impacts you’ve seen from the TransCanada long-term fixed-price agreement, what impact it’s had on producer behavior or expectations, understanding it’s still very early days at this point.

This is Brad. I think certainly the added value of that contract adds to certainly some producer optimism.

And I think what we’ve seen certainly through the first few days of November is, with that kicking in and some of the other alleviations there seems to be some strengthening in both gas production and pricing to go with it. So those are all optimistic.

Long term I think it’s really hard to understand how those are going to play out. But any added service I think is a positive for our producer customers.

Yes, so really too early to draw any conclusions in the long...

Yes, I think that’s fair.

Rob, this is Dave here. I think what I would say is that we’re certainly gratified to see the rebound in AECO price that we saw last week.

The Mainline toll agreement may have something to do with that, but the cold weather in Alberta probably had something to do with that as well. So I think that’s something that everybody is watching to see if we can see stronger AECO prices both on an absolute basis and in relation to NYMEX.

The Mainline toll certainly makes western Canadian gas much more competitive into the Ontario market. And so we’re cautiously optimistic that that’s going to help the economics for producers.

And hopefully that will help the recovery.

Yes. Just on the Chevron marketing deal, are there any volumes there currently that you’re able to participate in?

Or is your participation really contingent on their success with the drill bit?

Sorry. Maybe could you repeat that question one more time, please?

The question is whether this recent marketing agreement you signed with Chevron in the Duvernay, if that’s currently contributing or does it depend on success with the drill bit further development?

We don’t talk necessarily about different producers and what they’re currently sending through our fractionators, but they have been active in the area and I believe are probably marketing or processing some of their volumes. That contract there is specifically related to new drill bit volumes.

They have made a nomination under that agreement but we haven’t disclosed what that amount is.

Okay. And then just wondering, as you shut down the sour at Strachan, what’s the -- are there any sort of remediation expenditures you expect to make as a result of that?

There’s nothing in the immediate term. We continue to monitor our liabilities and kind of chip away at them at appropriate times.

And I think we will certainly do that at Strachan as well. But I don’t think it would be material one way or another.

Okay. Finally, you’ve talked about the credit rating changes.

But there’s been some other changes along the way, including the larger base shelf prospectus. So, Steven, I’m wondering what size of capital deployment or acquisition you think the company is prepared to undertake currently.

Well, the bankers keep telling us we have access to capital. Again, I wouldn’t read too much into the various measures.

But I do think it’s prudent as a management team and a company of our size to always make sure we’re in a position to be flexible enough to execute a range of sizes of transactions. Not afraid of larger transactions, but they for sure have to be prudent, well structured and deliver value to shareholders.

Maybe, Dave, you have some other comments.

Rob, I guess, yes, I would agree with what Steven’s saying. What we’ve done here with the shelf prospectus and with the credit ratings is just to create more options to make sure that we’ve got diversified sources of financing available to us.

But I wouldn’t read anything into that. We’re going to continue to focus on the things that we’re good at and continue to have a disciplined approach to new investments.

And as far as I know, we don’t have any elephants in our gun sights at this point, so I wouldn’t read too much into that.

Yes. The question wasn’t oriented to identify a specific asset, more so to understand sort of the strategy, what size of project are you looking to undertake.

Obviously you have a whole suite of singles and doubles. Just curious about the appetite for something significantly larger.

It seems like the appetite is there, but it’s got to fit within your sweet spot.

Exactly. I think that’s exactly the way I would describe it.

We certainly believe we’re of a size where we could do a sizeable new investment or acquisition. I would also emphasize we’ve had a number of potential financial partners approach us to indicate that they’d be very willing to co-invest with us if we were looking at something sizeable.

So we have -- we’re just trying to make sure that we have those options open to us. But it would be a little bit difficult for me to give you kind of an indication of what sort of size opportunity would fit or not, because it really depends a lot on the characteristics of the particular investment.

Right, of course.

Just on the North Wapati Pipeline and some of the other customers you might be talking to, just part of those discussions, do you think it’s a factor for those customers’ concerns about the ability to actually build a sour gas plant north of the Wapati River close to Grand Prairie and that could maybe work in your favor here?

I think it’s certainly a consideration for us. Building sour processing in a region with a lot of acreage country and certainly close to Grand Prairie will have its challenges, though not impossible.

I think our solution really we think gives producers line of sight to an approved facility with an approved acid gas injection scheme that would allow them to have good visibility to volumes coming online in the timeline we’re talking about. If the geology is as good as everybody is saying, there’s going to be need for more capacity out there.

And whether that’s north or south of the river, I think that will kind of evolve over time.

Okay. This next question may have been answered in some way just in terms of guiding to a bit of moderation in isooctane normally for Q4.

But I’m just wondering, with the refinery restarts in the Gulf and your product being good to bring gasoline back on spec, have you seen any lift in demand in pricing for that?

Well, we don’t really comment on our octane premiums. But I would say that the RBOB futures, if you look at that, have been pretty strong for next year.

And I would counter that that we do have some of that product hedged already, so -- you know, but we do have an opportunity to capture the higher RBOB prices that we see into 2018.

Okay. Just in terms of NGL pricing having come up and in the past some volumes have been kind of directed away from your facilities, given the stronger efficiency you’ve got, as the NGL pricing has come back have you noticed a trend in terms of volumes coming back into your facilities like Rimbey?

I think that’s fair. We’ve seen a lot of that throughout 2017.

We’ve had cases where producers have uptaken gas to their own plants. And we’ve got some specific examples in our world where producers are actually diverting their gas to our plants now because of the higher recoveries that we get out of them and the netbacks that we provide them.

So we continue to work with them on those and show them the value of our infrastructure right from both our Gathering and Processing and the NGL value chain that we add onto the end of that. So we’re always pleased when those things happen.

If I can just finish maybe on the results in Marketing and the realized losses. So it looks like the majority, $23 million of the $28 million, was due to product that’s still in inventory.

And I think, Dean, you mentioned that you’re well hedged, so I don’t -- is it fair that it wasn’t a situation where you saw upside in spot and therefore you bought hedges back to open up unhedged volumes? Is that fair?

Yes, that’s fair. We didn’t do that.

In terms of our propane strategy this year, we used more of our cavern assets. So we stored more propane in the summertime to sell it in the wintertime.

But when we went to hedge it we didn’t see a lot of winter contango in the market. So we opted to just sort of do monthly rolls on our hedges, month-to-month rolls on our hedges, to protect the value of the inventory until we saw the winter market move, which is what we saw in the last two months.

So once the winter market moved, we let our monthly roll expire and then we went and hedged out and locked in the winter contango.

Now I guess, though, in some ways, though, is that a greater risk strategy in the sense that if you’re rolling month-to-month and Q3 pops, but flattens out on the winter, you’re going to book the realized loss and not get the benefit in the winter months?

Well, what we would do is, yes, we would record still a big -- a larger loss. When we look forward we would still preserve the value of the physical inventory and then we would crystallize the higher value when we sell the physical product.

But you are opening yourself up to timing risk if the curve twists on you. Correct?

Yes, I think to some extent that’s probably true, Robert. This is David here.

I think to some extent that’s probably true that if you were to see a backwardation in the propane curve, then that probably would affect our margins somewhat. But the advantage we have as a physical storage operator is we have a pretty good handle on what the fundamentals are.

And coming into this winter with a more balanced North American supply-demand picture, I think we saw that that risk was pretty close to zero.

And just last, have you maintained the ability to put product in a lot of different North American markets that could give you optionality if we see certain regional pricing spike this winter?

Absolutely. We do move our product to a lot of different markets, even all the way into Mexico.

So we do have some flexibility on that front.

Thank you. That completes our third quarter conference call.

If you have any other follow-up questions please feel free to either give Nick or myself a call. Our contact information is in yesterday’s release.

Thank you for listening and participating, and have a good day.