Keyera Corp.

Thank you and good morning everyone. It’s my pleasure to welcome you to Keyera’s year-end conference call.

With me are David Smith, President and CEO; Steven Kroeker, Senior Vice President and CFO; Brad Lock, Senior Vice President and COO; and Dean Setoguchi, Senior Vice President and Chief Commercial Officer. We will open the call to questions once we complete our prepared remarks.

Before we begin today, I would like to remind listeners that some of our comments and answers that we will be providing 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, 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 described 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 2018 year-end report that we published yesterday and it’s 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. Yesterday, we reported our 2018 year-end financial results, even with the challenging industry environment; we focused on what we can control to deliver our strongest year ever.

All of our key financial metrics achieved record levels. With confidence in our business outlook, we maintained our dividend track record and increased our dividend by 7% in mid-2018.

Since we became a corporation in early 2011, Keyera has invested over $5 billion and deliver a compound annual growth rate of approximately 9% for both distributable cash flow and dividends, both on a per share basis. During 2018, Keyera achieved a number of operational milestones with strong demand for our services; we handled record volumes at our Fort Saskatchewan fractionation facility, our Simonette gas plant, and through our condensate system.

In addition, we carried out the largest capital program in our company’s history. Even with this increased activity, Keyera’s employees remain dedicated to safety achieving the zero lost-time incidents for the year.

Keyera continues to execute successfully on our strategy, expanding and enhancing our network – our integrated network of assets with disciplined capital allocation. We have $2.1 billion in approved project currently underway, mainly focused on establishing a strong position in the liquids-rich Montney and Duvernay development areas.

The capital program begins delivering incremental fast flow mid-2019 when phase one of our Wapiti gas plant comes on stream. This begins the next phase of step changes in Keyera’s growth as we expect to complete all of the projects in the $2.1 billion capital program within the next 24 to 30 months.

Once all of these projects achieve their annual run rate targeted for 2022, we expect this capital program to earn an annual return on capital between 10% and 15% consistent with our historical returns. I am confident that Keyera is doing the right things to continue to grow our business and bring value to our shareholders in the current industry environment.

With that, I’ll turn it over to Dean Setoguchi.

Thanks, David. The Gathering and Processing business unit generated operating margin of $272 million in 2018 compared to $275 million last year.

Although natural gas prices continue to be challenged, results from a Gathering and Processing statements were stable as producers remained active in liquids-rich areas of Alberta. For Keyera, this was most notable at our Simonette gas plant in Northwestern Alberta, which processed record volumes in 2018.

Overall, Keyera’s growth processing volumes increased 5% over the prior year. With the completion of our development plants at our Simonette, Wapiti and Pipestone gas plants, we’ll have a significant position supporting Montney development in Northwestern Alberta.

Our three gas plants will provide 950 million cubic feet a day of sour gas processing capacity and 90,000 barrels per day of condensate handling facilities. Simonette, Wapiti and Pipestone gas plants support some of the most attractive returns for producers were actively drilling in the Montney.

Keyera’s focus on providing integrated midstream solutions for our customers, which includes offering a full suite of services such as NGL fractionation, marketing, a water disposal solution at Wapiti and the most reliable, efficient and environmentally responsible process for handling sulfur and carbon dioxide with acid gas injection facilities at each plant. As David mentioned, we expect the first major project, phase one of Wapiti gas plant to be generating incremental cash flow by mid-year.

This will be followed by the expansion of the Simonette gas plant by the fourth quarter of 2019, phase two of the Wapiti gas plant and the Wildhorse Terminal by mid-2020 and then the Pipestone gas plant in 2021. These projects are expected to add meaningful EBITDA over the next three years as they come on stream and volumes ramp up.

The Liquids Infrastructure segments generated a record operating margin of $324 million in 2018, representing a 14% increase over the prior year. This was primarily due to incremental margin from recent capital investments such as the Norlite diluent pipeline and the Base Line Terminal, and increasing demand for many of our liquids infrastructure assets and services.

Our condensate system supports oil sands production and in 2018, we handled record volume through our system. In early 2019, we added another shipper on the Norlite pipeline on Keyera’s proprietary condensate system.

This is the third new customer that is signed up for long-term service since Norlite became operational. Our condensate hub is backed by long-term fee-for-service agreements with major oil sands producers to provide transportation and storage to meet their growing diluent needs.

The system is attractive to producers as it provides them with optionality and flexibility given all of our condensate receive points and delivery options and access to our storage. In addition, our system offers built-in capacity and reliability with assets such as the new South Grand Rapids diluent pipeline.

Keyera continues to pursue opportunities for our next growth platform. In the fourth quarter of 2018, we entered into a 50/50 joint venture with Wolf Midstream for the proposed development of an NGL and condensate gathering system called the Keyera – sorry, the Key Access Pipeline System, KAPS.

This proposed pipeline system would include the construction, two parallel pipelines to bring condensate and NGLs from the prolific Montney and Duvernay geological zones to Alberta’s NGL hub in Fort Saskatchewan. A final investment decision is expected to be made in the first half of 2019 subject to obtaining sufficient customer support.

Our marketing business continues to be a strong contributor to Keyera’s success, levering record results in 2018 with realized margin of $296 million. Over the past five years, the marketing segment has generated over $1 billion in realized margin.

Our marketing activities enhance returns from our fee-for-service business and provide an additional source of funding for our capital projects. Keyera’s marketing segment creates value by utilizing your integrated gathering, processing and liquids infrastructure assets including storage, fractionation and transportation capabilities.

We also upgrade low value butane into high value iso-octane at our AEF facility. With that, I’ll turn it over to Steven to discuss the financial results in more detail.

Thanks, Dean. As mentioned earlier, we had an outstanding year with each of our key financial metrics achieving record results.

Net earnings grew 36% to $394 million. Adjusted EBITDA increased 31% to $807 million and distributable cash flow rose 25%, $638 million representing the 14% increase on a per share basis.

All three of our business segments had an impressive year. Our Liquids Infrastructure and Marketing segments both generated record financial results, while the Gathering and Processing segment delivered stable results year-over-year.

Our three business segments also had a strong finish to the year, delivering strong results for the fourth quarter of 2018. The Gathering and Processing segment generated operating margin of $74 million, which included a one-time upward revenue adjustment for $6 million.

The Liquids Infrastructure segment earned $84 million reflecting the completion of the baseline terminal as the last tank came into service in October. And the Marketing segment reported a $106 million in realized margin.

Marketing’s impressive results were largely due to higher contributions from Keyera’s iso-octane and condensate business, plus our effective risk management strategy. Fourth quarter provided a good indication of the effectiveness of our hedging strategy as commodity prices declined sharply.

As a result of this hedging strategy, we had $67 million of realized gains in the fourth quarter on the settlement of risk management contracts. $23 million of these gains were related to risk management contracts put in place to protect the value of our butane that is used to produce iso-octane at our AEF facility.

While this butane inventory value is protected and cash gains were realized in the fourth, it will mean this higher price inventory will factor into iso-octane margins realized in 2019 when the butane is consumed by AEF. For 2019, we are maintaining our maintenance capital guidance between $100 million and $110 million, which includes both turnarounds at certain gas plants and non-recurring expenditures at Keyera Fort Saskatchewan and AEF as described last quarter.

However, we have updated our cash tax guidance following the introduction of the accelerated investment incentive announced by the federal government last fall. We now expect our 2019 cash taxes to be approximately $25 million lower than our previous guidance and range between $75 million and $85 million.

Our 2020 cash taxes are also expected to decrease, now estimated to be less than $10 million. Keyera continues to execute on our growth capital programs and in 2018, we invested $1.3 billion in growth projects and acquisitions.

This program included the completion of the Base Line Terminal, the Keylink NGL pipeline systems, liquids enhancements at our Simonette gas plant and the Pipestone liquids hub. All of these projects are generating incremental fee-for-service cash flows.

In 2019, we plan on investing between $800 million and $900 million excluding acquisitions to advance our capital projects at the Simonette, Wapiti and Pipestone plants, and the Wildhorse Terminal. Recognize the dynamic environment that we operate in, Keyera has maintained a strong financial footing and is well positioned to fund our current $2.1 billion capital program.

To date, we have funded approximately one third of this capital program while maintaining a net debt-to-EBITDA covenant ratio of 2.6 times. This is significantly below our debt covenant limit.

With respect to finding the remaining portion of this capital program, we do not plan on issuing common equity apart from the existing DRIP program and are comfortable operating in a net debt-to-EBITDA covenant ratio about three times. As well in the event Keyera and Wolf Midstream reach a positive final investment decision on the proposed KAPS project, Keyera believes it is well positioned to fund our 50% ownership interest in Keyera.

Most of the spending on Keyera is expected in 2020 and 2021 when our existing capital program is concluding. Assuming our current capital program is completed according to schedule.

We expect KAPS would be funded without issuing common equity apart from our DRIP program. That concludes my remarks, David.

Thanks, Steven. Although our industry continues to face a number of challenges, Keyera’s year-end results demonstrate demand for our products and services continues to be strong, while our marketing services continue to create value year-after-year.

We expect to deliver another year of strong financial performance as we kick off the next phase of our cash flow growth with phase one of the Wapiti gas plant. Market fundamentals are moving in our favor as more natural gas liquids are being produced from the Western Canada Sedimentary Basin.

As the year unfolds, this is expected to result in higher fractionation fees as well as lower butane prices in Alberta that benefit our iso-octane business. Keyera is well positioned to profit over the long-term as well as we continue to execute our strategy focused on maximizing cash flow from our existing assets, building a strong footprint in the liquids-rich Montney and Duvernay development areas in Northwestern Alberta.

Pursuing high return opportunities to expand and integrate our value chain into major U.S. liquids hubs and improving market access by considering opportunities further down the value chain.

On behalf of Keyera’s Board of Directors and management team, I would like to thank our employees, customers, shareholders, and other stakeholders for their continued support. Our team is committed to delivering another year of strong financial performance, operational excellence and project execution.

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

Hey, good morning. I appreciate the return on the capital guidance.

Just wondering if we can view the bottom end of that 10% to 15% range, as you know somewhat of a hurdle rate as you look to sanction future projects in the Montney and elsewhere. And perhaps we can speak to, what needs to happen to achieve the upper end at 15%.

Does that assume 100% utilization at the facilities? And would that encapsulate any upside for marketing?

Hi, it’s Dave here; I’ll try and respond to that. The range that we’re providing is it’s an average and it’s an aggregate and it represents a number of different scenarios that we look at with each one of the – with each one of our capital investment projects.

So, I’m not sure we can be more specific about what the assumptions are behind the low and the high end of the range unless we were to do it on a project-by-project basis and that’s not a disclosure that that we’re prepared to provide. What I can tell you is that, when we look at a project, we expected to stand on its own merits without the benefit of some of the upside opportunities that we often see when we’re looking at the integrated value chain.

That’s great. And then just moving over to the cash discussions here and with respect to the level of interest from the customers, I’m wondering if you could speak to some of the moving dynamics here since November, we’ve seen production curtailments another piece of pipeline expansion and some new competition from private equity in the Wapiti area.

So, just wondering if the level of interest is still as strong today as it was back in November.

I’ll take a shot at that and then Dean can chime in. I think we’re very encouraged by the responses that we’ve seen.

We continue to see drilling activity in that area continuing to be strong. And when we talked to producers about particularly what condensate, but also about NGL mix, they tell us two things.

One is that there is going to be more than enough volume to fill the incremental capacity that Pembina has been talking about and the Keyera’s – Keyera and Wolf are proposing. And the second thing they tell us is they would dearly love to have a competitive alternative.

And so for the both of those reasons, we’ve been getting pretty good traction and I feel like that our timing is pretty good.

Great. And then one last question if I could just on this most recent outage at AEF, wondering if you could just walk us through what happened there is a recurring issue at the plant, something completely new and unavoidable.

And then maybe if you could – if you had an internal availability target for the plant going forward? That’d be great.

This is Brad. So we had a minor leak in the facility that occurred kind of in the mid-February, when we assessed it, we found that there was, we couldn’t isolate it.

So, we were forced to take the facility down to deal with it. It’s been repaired and turned back over to operations that we’re in the process of bringing the plant back up right now.

So, as we indicated, we expect it to be back up by the end of the month and we don’t expect it to be a recurring issue.

Great. Any internal availability targets for the plants going forward?

Well, I think we continue to target running at or above nameplate. So, and I don’t think, anything that we’ve seen would prevent us from doing that through the remainder of this year.

Great. That’s it for me guys.

Thanks a lot.

Good morning everyone and congrats on the good quarter. I want to first start off on your Gathering and Processing business.

If we just look at the volumes at your plants, it seems like they were trending up through the end of the year. Just want to get a sense of what your expectations are for 2019 and just given the drilling activities, is that kind of small increases in volumes and some of these plants a trend that could continue through 2019?

Yes.

Rob, this is Brad here again. So I think, certainly, the stronger pricing as you get into the back half of the year, drives some increased volume.

So, I think that’s somewhat expected. As we look out into 2019, the pricing forecast is – continues to be softer in the summer and then in the winter.

So, it’s not unreasonable to expect a little bit of variability through the summer months as opposed to the winter months. That being said, we’re still seeing some activity behind our plants.

So hopefully, that’s going to temper some of that variability that we might have seen in previous years, but it’s hard to say until we kind of get into the – get into the spring, summer season.

All right, that’s helpful. And then moving over to marketing, and I realized there’s a number of moving parts here, but when you look at what you’ve seen so far in Q1 versus Q4, is it fair to say that you’re seeing some of the similar dynamics if we adjust for the butane contract realization?

Rob, I would say that in Q1, we’ll have to adjust for a couple of factors and one being our AEF facility being down for two to three weeks that a factor being the higher feedstock prices that butane prices for the first quarter until we get into the next contract here starting on April 1. And then notably, RBOB and WTI prices are quite a bit lower than last year.

So, I think until we get in the second quarter, you will start seeing the benefits of again, the low butane feedstock stock prices, which will be certainly an average of our new contract prices and the inventory that we still have available coming into the quarter as well.

And the only thing I would add to that – this is Steven, the only thing I would add to that is again, because of our hedging strategy we do look forward to try and hedge RBOB margins as well. And so we do expect to have some of that benefit as well in Q1 and going forward.

All right. And then just maybe a broader comment, just given how weak butane has been in Alberta, even relative to where it’s training in WTI [ph] versus propane, is that a dynamic that is expected to persist through 2019?

I’m just trying to get a sense of how much butane benefit on the pricing you could get in 2019?

I’ll take that one, Rob. I think, our outlook for the foreseeable future at least is that NGLs in general throughout North America are going to be in a somewhat of an oversupply situation.

And I think what we’re – what we’ve seen through 2018 is we’ve seen that the prices in Western Canada get discounted just because of the transportation costs and more limited market outlets. And we don’t see that changing very much throughout 2019 as we sit here today.

That’s our view. Having said that, as dean mentioned earlier, we have a mix of terms, supply contracts as well as shorter-term or spot-oriented pricing, and we have a mix of different pricing mechanisms on the butane.

So, I think we’re – I think we see it as a positive for our iso-octane business. But I wouldn’t assume that we can buy – that we’re buying all of our butane at spot, I guess what I would say.

Okay. That’s helpful.

Thank you.

Okay. thanks.

Good morning. On you commentary on the frac the [ph] outlook, is that that also based on some of the conversations that you’re having with your counterparties?

Yes. I think the short answer Ben, is yes.

I mean, as you know, during Q1, we’re in the – we’re in the throes of the annual recontracting and some of our recontracting is for longer-term and our commentary is reflective of those conversations.

Okay. And is there also anything to think about outside of NGL infrastructure as you look to potentially lock in higher frac fees?

I’m not sure what you mean by that.

I was just making a few years back when frac fees saw some compression; there were some locational changes on the marketing side that you were able to offset some of that weakness. And does it essentially reverse then looking at our way?

I mean, I guess in other words, this is a volume that you’re seeing sustain itself as your frac fees could go higher.

but we think our – we think the utilization of our fracs will be very strong in 2019 and David mentioned, we think the prices are going to be a bit firmer than what they’ve been in 2018.

Okay. All right.

And there’s only one last thing. I’ve checked some type of commentary around the funding and the debt-to-EBITDA, there’s some commentary around your comfort level being above three times, and I wanted to clarify that.

Is that more of three – one in three times, because your business is much more visible now we’ll take our payers, is it more three times during this growth phase and you want to get down to two to three long-term.

Yes. Good question.

Ben, Steven here. Again, the disclosure we tried to provide was that with respect to the funding the growth portion at the times or maybe about three.

And so we’re comfortable with being above three times while funding the growth program. Again, it always depends on a variety of factors, where you are in the capital program.

Where are you are in the individual project cycle or the EBITDA performance. And so we just wanted to get some more guidance to people that our historical range of 2.5 to 3 is not that’s something to be so anchored on, we are going through a growth phase.

I think it also speaks, it also speaks to the confidence that we have in the $2.1 billion program, that we talked about and the returns that will generate from that investment. And again, a third of that money is already – was already invested in 2018 and previous.

So, we have two thirds left to go and we’ll be wrapping up that cash flow profile from those investments.

Okay. Got it.

That’s great. Thanks for providing auto additional disclosures.

That’s very helpful. Thanks.

Thank you. I’m wondering if you could just help us understand that return on capital range, how long it might take to ramp up to the full run rate within the range that tend to be on that.

Yes. Linda, it’s Dave here.

As I said earlier, it’s a variety of different projects that we’ll sort of achieve their annual run rate at different times. We picked 2022, because I believe the Pipestone project is probably the last one to sort of achieve its full run rate and that would be in the 2022 timeframe.

So that that’s why we picked 2022 is sort of a target for that level of return.

Okay. Thank you.

And based on your outlook for the North American NGL markets being kind of net long for the foreseeable future, how does that factor into any sort of decision to twin or expand AEF and what other factors that might consider and when at the earliest might that happen?

Well, it’s something that we continue to look at, but it’s not something that’s imminent, Linda, I mean, as I always point out, with AEF, we acquired that facility yet. What we think is somewhere between 20% and 25% of its replacement cost.

So, the economics of twinning it are quite different than the economics associated with the original acquisition. Having said that, we’re always looking at opportunities to enhance the production to debottleneck and we will look in the future at expansion possibilities.

But as I said earlier, it’s not something that’s imminent.

Okay. That’s helpful.

And maybe, you could just elaborate as well on a little bit more on the value proposition for customers that that KAPS has. You mentioned a competitive alternative and capacity.

Are there other attributes in terms of flexibility or customized services or potentially some sort of cost dynamics that producers are looking for in your discussions?

There’s a number of features of the proposal that we’ve been working on with Wolf and discussing with our customers. I think at this stage of the process, Linda, would not be appropriate for me to get into the details as you can appreciate, it’s a competitive environment.

All right. I appreciate that.

Thanks so much. I’ll jump back in the queue.

Thank you. Good morning.

Maybe just a broad question to start with the implementation of the crude production quotas in Alberta, what were some of the broad impacts you’ve seen on your business just as – I guess since Jan 1 since the implementation.

I would say that the impact on our business has been negligible, if any. I mean we provide the services – and the services that we provide don’t really change in terms of those what the government has done.

I think Andrew, I think it’s fair to say we were expecting perhaps a little bit of a drop off and condensate demand. But we really haven’t seen that to any great degree.

One thing that I think that the condensate pricing in Canada has resulted in over the last few months is far fewer rail import barrels. So that’s the one part of our business, where – that just the, but that has more to do with the price of condensate and the supply demand for condensate more so than the – than the curtailments that were imposed on January 1.

And maybe just following up on that, when you think about the condensate market on a longer-term basis, and then Enbridge’s potential future actions on Southern Lights, what does that mean for your positioning within the marketplace?

I think it’s obviously these are all factors that we watch very carefully. You’ve seen a significant growth in condensate supply from Western Canada over the course of the last two or three years and we expect that that’s going to continue.

What we’re expecting and hoping is that we’ll see more crude oil export pipeline alternatives over the course of the next few years, which will provide, I think, some support for growth in bitumen production, which will provide a support for continued growth in demand for condensate and so as that’s another factor on the demand side. There has been lots of chatter about the possibility of Enbridge reversing Southern Lights, and that obviously will affect the supply demand picture in Western Canada for condensate.

Our perspective on it, obviously it’s something we watch carefully, but with our network, what we’ve tried to create is a lot of flexibility so that we are not as concerned with where the condensate coming from, and our customers have access to barrels from a variety of different sources.

Then I think on the demand side – on the demand side, you probably saw that Enbridge announced that they expect line three to be a – like line three expansion to be up and running by the end of the year. So, I think that’s – they’re actually 370,000 barrels per day, again, which is supportive for increased bitumen production, but also a condensate, a deal and demand as well.

Okay, that’s helpful. And then one final, more maybe nit-picky question.

The 40% of the pipe that you bought the raw gas pipe across the really [ph] grain, how much would that cost to connect into your existing infrastructure, roughly?

This is Brad, it would be small. So, the pipe really just fills a gap right now.

And so the dollars would be very, very small.

Okay, great. Thank you.

Hey, good morning. We’re not accustomed to seeing Keyera put out a potential FID date on a project as you have here with cops.

What’s changed to cause you to do that?

Rob, I think we feel like we’re getting really close. We’re not prepared to get into details, but I think last fall, we were saying some time in 2019, I think now we’re getting more confident in seeing it in the next few months.

Okay. And you made a comment about the funding assumption that there was a confidence level in the project execution to indicate that you can internally finance just with the DRIP.

is there another financing assumption in there? And I’m thinking perhaps preferred shares or is this, can you do this just for the internally generated cash flow and the DRIP?

Yes, good question, Rob. There’s no explicit assumption about having to use hybrids.

Obviously, that’s always an avenue available to us if we – if the things change in terms of business environment or something like that, but there’s no explicit assumption.

Okay. And then finally, there was that Redwater case recently about well abandonment liabilities and I’m just wondering what you’re hearing from producers and what they’re telling you about the impact that’s on their activity levels, specifically wondering if there’s a shift at the spending maybe to more treatment of those abandonment liabilities as opposed to new drilling?

Rob, I think the concern that I’ve heard expressed, and this is really more speculative at this point, that the concern that I’ve heard expressed is just a concern about availability of debt financing. I think that the concern is that the Redwater decision is going to cause lenders to be more cautious with their borrowing base determination and their willingness to lend at the same levels.

But as I said, I think this is more speculation at this stage. I don’t know that there’s been very much discussion on that.

So that’s really, I think more the concern that some producers have is just the availability of a debt funding. We don’t frankly expect is going to have a huge impact in our areas, because most of our – most of our customers are living within cash flow right now.

So, access to incremental debt financing is not something that they’re relying on. As far as the level of spending on – I think maybe what you were suggesting is that the companies would be spending more money on reclamation.

I don’t think that that’s something that we expect to see in the near-term. Most prudent operators have a program of abandonment for the wells that are subject to that requirement.

And I don’t see that those programs, I don’t see those programs being accelerated as a result of the decision.

Okay. That’s good color.

And just to follow-up question then for Steve. I’m wondering if you’re hearing any shift in tone with respect to the asset retirement obligations like Keyera has and how those are treated with respect to that capacity?

No, we haven’t heard anything really around them.

Okay. Thanks guys.

Thank you. This completes our year-end conference call.

If you have any questions that you need to follow-up on, please give me a call later today. Thanks for listening and have a good day.