Earnings Call: Q4 2018

Feb 22, 2019

Good morning. My name is Casey, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corporation Year End Results 2018 Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. Thank you. Lavonne Zdunik, you may begin your conference. 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 Stephen Kroeker, Senior Vice President and CFO Brad Lock, Senior Vice President and COO and Dean Setiguchi, Senior Vice President and Chief Commercial Officer. We will open the call for questions once we complete our prepared remarks. Before we begin today, I would like to remind listeners that some of the 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, 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 described in our publicly filed disclosure documents available on our website and SEDAR. We encourage you to review the MD and 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-twenty 18. Since we became a corporation in early 2011, Keyera has invested over $5,000,000,000 and delivered 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 remained dedicated to safety, achieving 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 $2,100,000,000 in approved projects currently underway, mainly focused on establishing a strong position in the liquids rich Montney and Duvernay development areas. The capital program begins delivering incremental cash flow mid-twenty 19 when Phase 1 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 $2,100,000,000 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 of between 10% 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 Setiguchi. Thanks, David. The Gathering Processing business unit generated operating margin of $272,000,000 in 2018 compared to $275,000,000 last year. Although natural gas prices continue to be challenged, results from our Gathering Processing segment were stable as producers remain active in liquids rich areas of Alberta. For Keyera, this was most notable at our Simonet Gas Plant in Northwestern Alberta which processed record volumes in 2018. Overall, Keyera's gross processing volumes increased 5% over the prior year. With the completion of our development plans at our Simonette, Wapiti and Pipestone gas plants, we'll have a significant position supporting Montney development in Northwestern Alberta. Our 3 gas plants will provide 950,000,000 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 who are actively drilling in the Montney. Gera is focused 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 1st major project Phase 1 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 Q4 of 2019, Phase 2 of the Wapiti gas plant and the Wildhorse terminal by mid-twenty 20 and then the Pipestone gas plant in 2021. These projects are expected to add meaningful EBITDA over the next 3 years as they come on stream and volumes ramp up. The Liquids Infrastructure segment generated a record operating margin of $324,000,000 in 20.18, representing a 14% increase over the prior year. This was primarily due to incremental margin from recent capital investments such as the Norlite Dilwin pipeline, the baseline 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 volumes to our system. In early 2019, we added another shipper on the Norlite pipeline and Keyera's proprietary condensate system. This is the 3rd new customer that has signed up for long term service since neurolite 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 Q4 of 2018, we entered into a fifty-fifty joint venture with Wolf Midstream for the proposed development of an NGL and condensate gathering system called the Key Access Pipeline System, CAPS. This proposed pipeline system would include the construction of 2 parallel pipelines to bring condensate and NGLs from the prolific Montney and Duvernay geological zones to Alberta's NGL hub and Fort Saskatchewan. A final investment decision is expected to be made in the first half of twenty nineteen subject to obtaining sufficient customer support. Our marketing business continues to be a strong contributor to Keyera's success, delivering record results in 2018 with realized margin of $296,000,000 Over the past 5 years, the marketing segment has generated over $1,000,000,000 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 our 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 Stephen 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 394,000,000 dollars adjusted EBITDA increased 31 percent to $807,000,000 and distributable cash flow rose 25 percent to $638,000,000 representing a 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 3 business segments also had a strong finish to the year, delivering strong results for the Q4 of 2018. The Gathering and Processing segment generated operating margin of $74,000,000 which included a one time upward revenue adjustment for 6,000,000 dollars The Liquids Infrastructure segment earned $84,000,000 reflecting the completion of the baseline terminal as the last tank came into service in October. And the Marketing segment reported $106,000,000 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. The 4th 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 $67,000,000 of realized gains in the Q4 on the settlement of risk management contracts. Dollars 23,000,000 of these gains were related to risk management contracts put in place to protect the value of our butane that is used to produce isooctane at our AEF facility. While this butane inventory value is protected and cash gains were realized in the Q4, it will mean this higher priced inventory will factor into isooctane margins realized in 2019 when the butane is consumed by AEF. For 2019, we are maintaining our maintenance capital guidance between $100,000,000 $110,000,000 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 $25,000,000 lower than our previous guidance and range between $75,000,000 $85,000,000 Our 2020 cash taxes are also expected to decrease, now estimated to be less than $10,000,000 Pierrot continues to execute on our growth capital programs. And in 2018, we invested $1,300,000,000 in growth projects and acquisitions. This program included the completion of the baseline terminal, the KeyLink NGL pipeline systems, liquids enhancements at our Simonette gas plant and the Pipestone liquids hub. All these projects are generating incremental fee for service cash flows. In 2019, we plan on investing between $800,000,000 $900,000,000 excluding acquisitions to advance our capital projects at the Simonette, Guapiti and Pipestone plants and the Wildhorse Terminal. Recognizing the dynamic environment that we operate in, Deerend has maintained a strong financial footing and is well positioned to fund our current CAD2.1 billion capital program. To date, we have funded approximately 1 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 funding 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 at a net debt to EBITDA covenant ratio above 3 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 percent ownership interest in CAPS. Most of the spending on CAPS is expected in 2020 2021 when our existing capital program is concluding. Assuming our current capital program is completed according to schedule, we expect caps will be funded without issuing common equity apart from our DRIP program. That concludes my remarks. David? Thanks, Stephen. 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 1 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 ice octane business. Garrett 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 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. Thank And your first question here comes from Patrick Kenny with National Bank Financial. Please go ahead. Your line is open. Hey, good morning. I appreciate the return on capital guidance. Just wondering if we can view the bottom end of that 10% to 15% range as somewhat of a hurdle rate as you look to sanction future projects in the Montney and elsewhere. And perhaps if you 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 from marketing? Pat, 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 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 we're prepared to provide. What I can tell you is that when we look at a project, we expect it 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. Got it. That's great. And then just moving over to the caps discussions here and with respect to the level of interest from customers, wondering if you can speak to some of the moving dynamics here since November. We've seen production curtailments, another piece 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 talk to producers about particularly about condensate, but also about NGL mix, they tell us 2 things. 1 is that is going to be more than enough volume to fill the incremental capacity that Pembina has been talking about and that 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 both of those reasons, we've been getting pretty good traction and I feel like 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 this a recurring issue at the plant, something completely new and unavoidable? And then maybe if you had an internal availability target for the plant going forward that would be great. Sure. This is Brad. So we had a minor leak in the facility that occurred kind of mid February. When we assessed it, we found that there is 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, and 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. And 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. Your next question comes from Rob Hope with Scotiabank. Please go ahead. Your line is open. Good morning, everyone. Congrats on a 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 in some of these plants a trend that could continue through 2019? 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 than 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 spring summer season. All right. That's helpful. And then moving over to marketing and I realize 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 2 to 3 weeks. The other factor being the higher feedstock prices, the butane prices for the Q1 until we get into the next contract here starting April 1. And then notably, RBOB and WTI prices are quite a bit lower than last year. I think until we get in the Q2, you won't start seeing the benefits of, again, the low butane feedstock 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 here. 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 trading in W 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 somewhat of an oversupply situation. And I think what we've seen through 2018 is we've seen that 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 term supply contracts as well as shorter term more 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 isooctane business. But I wouldn't assume that we can buy that we're buying all of our butane at spot, I guess is what I would say. Okay. That's helpful. Thank you. Your next question comes from Ben Pham with BMO. Please go ahead. Your line is open. Okay. Thanks. Good morning. On your commentary on the frac D outlook, is 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 throes of the annual re contracting and some of our re contracting 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 thinking 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, does the volumes you're seeing sustain itself as your frac fees could go higher? We think our we think the utilization of our fracs will be very strong in 2019. And as David mentioned, we think the prices are going to be a bit firmer than what they've been in 2018. Okay. All right. And the only last thing I want to check, some of the commentary around the funding and the debt to EBITDA. There's some commentary around your comfort level being above 3x. And I wanted to clarify that. Is that more than 3x because your business is much more visible now with take or pay? Or is it more 3x during this growth phase and you want to get down to 2 to 3 long term? Yes. Good question, Ben. Stephen here. Again, the disclosure we tried to provide was that with respect to funding the growth portion, at times we may be above 3. And so we're comfortable being above 3 times while funding the growth program. Again, it always depends on a variety of factors where you are in the capital program, where you are in the individual project cycle or the EBITDA performance. And so we just wanted to give some more guidance to people that our historical range of 2.5% to 3% is not not something to be so anchored on while we're going through a growth phase. I think it also speaks to the confidence that we have in the $2,100,000,000 program that we talked about and the returns that we'll generate from that investment. And again, a third of that money is already was already invested in 2018 and previous. So we have 2 thirds left to go, and we'll be wrapping up that cash flow profile from those investments. Okay, good. That's great. Thanks for providing all the additional disclosures. It's very helpful. Thanks. And your next question comes from Linda Ezergailis with TD Securities. Please go ahead. Your line is open. 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 fit within that? Yes. Linda, it's Dave here. As I said earlier, it's a variety of different projects that will 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's why we picked 2022 as sort of a target for that level of return. Okay. Thank you. And based on your outlook for 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 might you 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 at what we think is somewhere between 20% 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 CAPS 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 dynamic that producers are looking for in your discussions? There's a number of features of the proposal that we've been working on with Wolfe and discussing with our customers. I think at this stage of the process, Linda, it would not be appropriate for me to get into the details. As you can appreciate, it's a competitive environment. I appreciate that. Thanks so much. I'll jump back in the queue. Your next question comes from Andrew Kuske with Credit Suisse. Please go ahead. Your line is open. Maybe just a broad question to start and with the implementation of the crude production quotas in Alberta, what were some of the broad impacts you've seen on your business just in, I guess since Jan 1, since the implementation? I wouldn't say that the impact on our business has been negligible, if any. I mean, we provide a service 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 in condensate demand. But we really haven't seen that to any great degree. One thing 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 just the but that has more to do with the price of condensate and the supply demand for condensate more so 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 2 or 3 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 support for continued growth in demand for condensate. And so as that's another factor on the demand side. There's been lots of chatter about the possibility of Enbridge reversing Southern Lights and that obviously will affect the supply demand picture in Canada for condensate. Our perspective on it obviously is 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 is coming from and our customers have access to barrels from a variety of different sources. And I think on the demand side, you probably saw that Enbridge announced that they expect Line 3 to be the Line 3 expansion to be up and running by the end of the year. So I think that's directionally 370,000 barrels per day, again, which is supportive for increased bitumen production, but also condensate diline demand as well. Okay. That's helpful. And then one final more maybe nitpicky question. The 40% of the pipe that you bought the raw gas pipe across the Willy Green, 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 the gap right now. And so the dollars would be very, very small. Okay, great. Thank you. Your next question comes from Robert Catellier with CIBC Capital Markets. Please go ahead. Your line is open. Hey, good morning. We're not accustomed to seeing Keyera put out a potential FID date on a project as you have here with CAPS. 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 sometime in 2019, I think now we're getting more confident in seeing it in the next few months. Okay. And the team made a comment about the funding assumption that there's 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 with internally generated cash flow and the DRIP? Yes. Good question, Rob. Yes. No, there's no explicit assumption about having to use hybrids. Obviously, that's always an avenue available to us if we if 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 of this 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, but the concern that I've heard expressed is just a concern about availability of debt financing. I think 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 debt funding. We don't frankly expect it's going to have a huge impact in our areas because 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 company 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 a follow-up question then for Steve. I'm wondering if you're hearing any shift in tone with respect to the asset retirement obligations that Keyera has and how those are treated with respect to debt capacity? No, we haven't heard anything really around that. Okay. Thanks guys. And there are no further questions in queue at this time. I will turn the call back over to Lavonne Zdunik for any closing remarks. 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. And ladies and gentlemen, this concludes today's conference call. You may now disconnect.