Earnings Call: Q3 2018

Nov 7, 2018

Good morning. My name is Chris, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corporation Third Quarter 2018 Results Thank you. Lavonne Siedanik, Director of Investor Relations, you may begin your conference. Thank you, and good morning. My pleasure to welcome you to Keyera's Q3 conference call. With me today, I have David Smith, our President and CEO Stephen Kreker, Senior Vice President and CFO Brad Lock, Senior Vice President of the Gathering and Processing Business Unit and Dean Sediguchi, Senior Vice President of the Liquids Business Unit. In a moment, David will provide an overview of the quarter, followed by operational updates from Brad and Dean. Stephen will provide additional information about our financial results. We will open the call to questions once we have completed our prepared remarks. Before we begin, I would like to remind listeners that some of our comments and answers that we will be providing today speak to future events. These forward looking statements are given as of today's date and reflect events or outcomes that management currently expects to occur based on their belief about the relevant material factors as well as our understanding of the business and the environment in which we operate. Because forward looking statements address future events and outcomes, they necessarily involve risks and uncertainties that could cause actual results to differ materially. Some of these risks and uncertainties include general economic market and business conditions, fluctuations in supply demand inventory levels and pricing of natural gas, NGLs, 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 and A, which can be found in our 2018 Q3 report published yesterday and is available on our website and on SEDAR. With that, I'll turn it over to David Smith, our President and CEO. Thank you, Lavonne, and good morning, everyone. Yesterday, we reported our Q3 financial results, and I'm pleased with the overall performance of our integrated business in a challenging environment. Adjusted EBITDA and distributable cash flow both increased in comparison to the same period last year. Net earnings were $35,000,000 for the quarter similar to the Q3 of 2017. We maintained a low payout ratio of 72% for the quarter and 61% for the year to date. Stephen will speak more to the financial results later in the call. Keyera continues to execute on our capital program. Since the beginning of the year, we have completed the baseline terminal, the KeyLink and Hull NGL pipeline systems, liquids handling enhancements at our Simonette gas plant and the Pipestone liquids hub. All of these projects are generating incremental long term fee for service cash flows. With increased production from liquids rich areas in Alberta, our liquids infrastructure and marketing segments are also benefiting. There is high demand for our fractionation storage and condensate facilities and we are transporting more volumes than ever before to end user markets. Keyera is well positioned for continued cash flow growth with our development plans at our Simonette, Wapiti and Pipestone gas plants and continued expansion of our liquids infrastructure. We are constantly looking for the right opportunities to expand, extend and enhance our integrated network of facilities. A good example is our proposed CAPS natural gas liquids and condensate pipeline system in Northwest Alberta, which Dean will talk about. Keyera has a history of prudent disciplined capital allocation, which we believe will continue to generate cash flow growth and long term shareholder value. With that, Brad Locke will now discuss our Gathering and Processing business unit. Thanks, David. The Gathering and Processing business unit delivered an operating margin of $64,000,000 in the Q3 of 2018, with gross processing throughput averaging 1,480,000,000 cubic feet per day, virtually unchanged compared to the same period last year. Volume growth at both the Simonette and Alder Flats gas plants was offset by volume declines at certain facilities, particularly the Rimbey and Minnehikbut Lake gas plants, where natural gas prices and lower producer activity have impacted gross processing throughput. During the quarter, we continued to progress our projects in the liquids rich Montney and Duvernay regions of Northwest Alberta to meet the growing needs of producers in the area. At our Simonette gas plant, civil work began to prepare for the acid gas injection and gas processing expansions. In the Wapiti region, we are fast approaching mechanical completion for Phase 1 of the gas plant and gathering system with all major equipment being received and installed at site. Engineering work and procurement of long lead items continues for Phase 2 of the gas plant and the North Wapiti pipeline system. In September, the Pipestone liquids hub became operational and is now generating incremental margin, while development of the Pipestone gas plant continues. These projects will begin to add meaningful cash flow beginning in mid-twenty 19 when Phase 1 of the Wapiti gas plant is completed and will continue to build as we complete the North Wapiti pipeline system and Simonette expansions in the second half of twenty nineteen followed by Phase 2 of the Wapiti gas plant in mid-twenty 20 and the Pipestone gas plant in 2021. These three gas plants support some of the most attractive geological developments in the Western Canada Sedimentary Basin, where producer economics are driven by the strong value of condensate rather than natural gas. Our long term plan will be to interconnect these 3 gas plants, providing producers with increased flexibility and reliability with 950,000,000 cubic feet per day of sour gas processing capacity and 90,000 barrels a day of condensate handling facilities. I will now turn it over to Dean to discuss the liquids business unit. Thanks, Brad. We're pleased with the performance of the liquids business unit in the Q3 of 2018 with solid results from our infrastructure and marketing segments. Operating margin for Liquids Infrastructure was a record $82,000,000 up 15% from the same quarter last year. These results were largely driven by increased demand for our condensate services and incremental margin from new assets, including the Norlite Pipeline and the Baseline Terminal. During the quarter, 5 tanks were completed and in October, the final tank was placed into service. Keyera will realize the full benefit of this asset in 2019, which is fully contracted with take or pay contracts up to 10 years in length. With increased production for the liquids rich areas in Alberta, we had strong demand for many of our liquids infrastructure assets and services. Our fractionators at Fort Saskatchewan operated near capacity. Utilization of our storage caverns were high and we handled record volumes through our condensate system. We're pleased to have completed the South Grand Rapids diluent pipeline. This new pipeline provides our customers with additional capacity, flexibility and reliability between Edmonton and Fort Saskatchewan and positions Keyera for future growth. As producers continue to focus on liquids rich Montney and Duvernay developments in Northwestern Alberta, we recognize the industry's need for a competitive NGL transportation solution from the area to Fort Saskatchewan, Alberta's NGL hub. In the Q4 of 2018, we entered into a fifty-fifty joint venture agreement with Wolf Midstream to develop the key access pipeline system, CAPS, a proposed liquids gathering system that would include a pipeline dedicated to transporting natural gas liquids and a second pipeline dedicated to condensate service. We continue to work with producers in the area on this egress solution and expect the final investment decision in 2019, subject to obtaining sufficient customer support and final cost estimates. Turning to our Marketing segment, we generated realized margin of $43,000,000 in the Q3 compared to $10,000,000 in the same period last year. We continue to benefit from a high contribution from our iso octane sales as well as contributions from our Oklahoma liquids terminal acquired in June. Our condensate business has also generated strong results as we move more volumes through our system to meet the growing needs of our oil sands producers. Our AEF facility has operated very well in 2018 and continues to maintain high utilization rates. To help ensure continued reliability and high utilization of the facility, we recently shut down AEF or preventative maintenance. The outage is not expected to have a material financial impact as demand and margins for iso octane are typically lower as we approach winter. We expect AEF to resume full operations by mid November. Looking to the Q4, we will be moving propane inventory to take advantage of the high demand winter months. We'll leverage our Josephburg rail terminal and marketing expertise to move propane to the highest value markets. As always, rail service is a key element of this strategy. We're working with the railways to achieve expected service levels. Our marketing business continues to be a strong contributor to Keyera's success. Year to date, it has generated over $190,000,000 in realized margin, providing cash flow that can be reinvested to help fund our capital program. With that, I'll turn it over to Stephen to discuss the financial results in more detail. Thank you, Dean. As mentioned earlier, we had a successful quarter as our 3 integrated businesses combined to deliver solid results compared to the same period last year. The Gathering and Processing business segment delivered operating margin of 64,000,000 dollars slightly down from the $69,000,000 reported in the same period last year. Reduced producer activity in certain areas combined with higher operating costs lowered our operating margin at some facilities. The Liquid Infrastructure business segment posted a strong quarter compared to the Q3 of 2017 due to full quarter results for the Norlite pipeline and partial start up results for Baseline Terminal. As well, there was overall growth in demand for Keyera's condensate network, including our transportation and storage services. The marketing segment's realized margin was $43,000,000 versus $10,000,000 in the Q3 of 2017 as isooctane's contribution benefited from short term demand that carried over from the Q2 into July. Our Liquids Blending and Condensate businesses were also strong contributors to realized margin. As a result of our integrated business performing well during the quarter, adjusted EBITDA increased 16% over the same quarter last year, while distributable cash flow was 7% higher on a per share basis. Our trailing 12 months adjusted EBITDA was $756,000,000 Net earnings were $35,000,000 and included $63,000,000 in impairment expenses as we reduced the value of the Minnehik Buck Lake and Zetta Creek gas plants due to reduced drilling activity and corresponding throughput volumes at these facilities. Looking ahead to 2019, we expect a full year cash flow contribution from various projects, including the Baseline Terminal, the Pipestone Liquids Hub, the Simonette Liquids Handling Expansion Project, the KeyLink NGL Gathering System and the Oklahoma Liquids Terminal. In addition, we expect the first phase of our Wapiti gas plant to be generating incremental cash flow by mid-twenty 19, followed by cash flow from the North Wapiti pipeline system and the Simonette expansion. Year to date, our maintenance capital is 37,000,000 dollars For 2019, we expect maintenance capital to range between $100,000,000 $110,000,000 which is unusually high for a year when we are not conducting a turnaround at AEF. The higher range includes approximately $50,000,000 in plant turnarounds planned at our Rimbey, Mennon North, Cynthia and Racinas gas plants, but also includes various nonrecurring costs. For example, it includes nonrecurring maintenance capital at our Keyera Fort Saskatchewan fractionator, some equipment procurement costs in advance of our turnaround of AEF in 2020 and a change out of one of our more Year to date, our cash taxes are $25,000,000 Given our Year to date, our cash taxes are $25,000,000 Given our deferred partnership structure, our strong operating results year to date and the timing of when assets related to our significant capital expenditures become available for use, we expect cash taxes for 2019 to increase to between $100,000,000 $110,000,000 before coming back down in 2020 to less than $20,000,000 dollars Our cash tax estimates assume our business performs as planned and our capital projects are completed as expected. As a reminder, in 2019, we expect approximately $950,000,000 of new assets in the Gathering and Processing segment to become available for use. And over 2020 2021, we expect a further $750,000,000 of new assets in the Gathering and Processing segment to become available for use. The tax pools related to these expected new assets have attractive capital cost allowance claim rates, which helps reduce cash taxes. With a net debt to EBITDA ratio of 2.7x at the end of the 3rd quarter and a payout ratio of 61% year to date, Keyera continues to be well positioned to fund its ongoing capital program. In turn, the capital program is expected to add meaningful incremental EBITDA to Keyera in each of the next 3 years. That concludes my remarks. David? Thanks, Stephen. Keyera continues to serve our customers' needs and as our Q3 results demonstrate, demand for our products and services is healthy. Although we're disappointed with the continued low drilling activity around some of our gathering and processing facilities, we are seeing signs of recovery in natural gas prices, and we're encouraged by Shell's decision to proceed with their West Coast LNG project and Imperial's decision to proceed with their Aspen oil sands project. Our facilities are well positioned to profit both short term and long term as the industry activity recovers. We continue to have a disciplined strategy focusing on maximizing cash flow from our existing assets, building a strong footprint in the liquids rich Montney and Duvernay developments in Northwestern Alberta and pursuing opportunities to expand and integrate our value chain in the Western Canada Sedimentary Basin and the U. S. In 2019, we are planning to invest growth capital of between $800,000,000 $900,000,000 primarily focused on projects already underway that support these strategies. Keyera's strong balance sheet and excess distributable cash flow position us well to fund this current capital program. We look forward to a strong finish in 2018 and cash flow growth in 2019 with a continued focus on operational excellence and project execution. On behalf of Keyera's directors and management team, I would like to thank our employees, customers, shareholders and other stakeholders for their continued support. With that, I'll turn it back over to the operator. Please go ahead with questions. Your first question comes from Linda Ezergailis of TD Securities. Your line is open. Thank you. I'm wondering if you could help us understand a little bit more about your proposed CAPS project. Specifically, I'm wondering what does each partner bring to the JV? How might we think of the timeline beyond FID to get to an in service date and key milestones? And I realize there might be some sensitivities to providing any sort of ballpark cost estimates. But to the extent that you can give us some parameters around that, that would be helpful. Hi, Linda. It's Dean. That's a lot of questions. But we are very excited about our CAPS project. Our partner is Wolf and obviously you probably know some things about Wolf and you can check out their website I guess to find out more about the company. But really the principles of that company are the guys who built the Vantage pipeline. So pretty impressive work on what they did there crossing 3 jurisdictions from the U. S. Into Saskatchewan, Alberta. So they bring a lot of expertise from that front and they're a very good partner to work with. So we're very pleased to have them as a partner. In terms of overall cost, we are working towards our Class III estimate and we will have that early in the next year. So right now we don't have any sort of numbers that we're prepared to share, but we're continuing to refine our estimates. And part of that is our initial scoping of the pipeline would take it out to our Pipestone gas plant. But we are evaluating interest beyond that to the Northwest, but the pipeline is expected to be just in Alberta. Sorry, did I answer all your questions? Yes. Timeline as well would be helpful beyond FID. Sure. Yes. The timeline would be in service early in 2022. And the bulk of the capital expenditures as laid out today would occur in 2021. So really it would be after the capital expenditures that we've committed to so far. So beyond that time period and the projects that we have on the table today they'll be contributing cash flow to help those expenditures out in 2021. So the timeline fits in with our capital program and funding needs as well. Thank you. And would you expect to get your full customer support in advance of FID or some sort of minimum threshold and then continue to build up after FID? Yes. We would want enough commitments to establish a base return for this project. And we've often been asked the question of how much volume you need and that's not an easy answer. And part of it is, is when the volumes come in the system because the further you are out on the pipeline, the tolls are higher. And it also relates to term and sort of volume and term of commitment. So there's a lot of variables that are involved in terms of how much we need to actually sanction this pipeline. And just an operational question to understand your expensive catalyst that you're replacing at AEF next year. Is there some sort of modest incremental bump in efficiency that declines over the 4 or 5 years? Or is it really just seamless and no material change in operations between new versus old catalyst? Yes. What happens is that we've actually been very successful in running our facility above nameplate capacity. And over time though that creates a bit more wear and tear on the facility. In fact, we just completed one of our longest continuous run times in plant history. But again with that there's some repair and maintenance that has to be done to keep that AEF performing at high utilization rates. That's why we have to change out the catalyst. And the reason why it's shut down right now, part of it is because we're replacing the dimerization catalyst and next year we're planning to replace the Olaflex catalyst. There's different kinds of catalysts that have different expected lives. The good thing about our change out of the Oloflex catalyst next year is that we don't think we have to shut down the facility to do that. Okay. That's helpful. I'll jump back in the queue. Your next question comes from Rob Hope of Scotiabank. Your line is open. Good morning, everyone. Maybe just a follow-up question on caps. So I appreciate that you could have an origin at Pipestone. Just wondering, will Pipestone have also a connection to another competing pipeline? And do you have a base level of volume commitments secured so far? Our pipeline is our planned pipeline is basically to connect several gas plants up in the Montney Duvernay, including our own, and connected into Fort Saskatchewan. And initially it will be connected to our KFS facility and with plans to connect to other fractionators in Fort Saskatchewan as well to provide a competitive alternative. Thank you. And do you have any commitments so far that you're working off of? Or is it relatively open so far? Rob, we are just working with customers right now and we can't disclose I guess what we have so far, but we're continuing to work with our customers on those commitments. Okay. Thank you. And then just moving over to maintenance, appreciate the color on the 2019 maintenance number. Just looking over at 2020 though, AEF was north of $50,000,000 a couple of years ago and you also do have some relatively large plants coming up for turnarounds as well. Just wondering is 2019 indicative of 2020? Yes, Stephen here. We haven't gone through and done all our estimating yet for 20 20, so too early to tell. But directionally, I think you're right in terms of turnarounds at some of our bigger facilities in 'twenty and our AEF facility, obviously. Obviously. Yes. I think 2020 AEF will be in 2020 and that will be the big one, Rob. I think the significant G and P facilities will be done this year and next year. Thank you. I'll hop back in the queue. Your next question comes from Ben Pham of BMO. Your line is open. Okay, thanks. Good morning. I wanted to go back to the CAPP's project And I'm wondering, can you talk about perhaps the positive implications downstream on the fracs, the storage, the marketing? Would this lead to potential expansions downstream? And then when you think about those additional revenue streams, is that part of your base return that you're thinking about where you might not get the targeted volumes initially, but you should be including the additional revenues downstream? Ben, it's Dean again. Well, we have a partner, which is Wolf fifty-fifty. And this has to CaPS has to meet our joint investment hurdles on a standalone basis. But you bring up a very good point that if this project is sanctioned, it will generate more business and service needs on the downstream side of our business including fractionation storage and also our marketing services as well. So we believe that that will help our entire integrated value chain. Anything on the U. S. Side, what you have now, what you can do to integrate even maybe North American, maybe that's a bit of a stretch, but is that something to think about there? Well, today, I mean, as you know, we have the whole rail and truck facility that is pipeline connected into Mont Belvieu. And you've probably seen that the differentials are pretty wide between have been very wide between Conway and Mont Belvieu. So again, it's helped our Canadian business by having that high value market outlet for our products and mainly propane. So we are sort of integrating some of our U. S. Assets into our business plan already. Okay. And a question on the balance sheet. I know, Steve, you mentioned 2.7 times debt EBITDA, product the lowest leverage in the Canadian universe. How do you kind of see that trending next year, high CapEx this year, high CapEx next year? Are you exceeding the 3 times debt to EBITDA? And if you are, would you be comfortable being above that range? Yes. Hi, Ben. Yes, no, we do see it trending up modestly into 20 19, again, new EBITDA coming on throughout 2019, full run rates on various assets as well. It will probably get to that 3 ish time range in that area. And from that point of view, we'd be comfortable in that kind of range. Historically, I think we've said 2 to 3, but as assets become more and more fee for service, it does give us flexibility there. And as well, you're always looking through projects too to see when the rest of the EBITDA is coming to. So I wouldn't say it's always a hard and fast. I think you always just have to continue to manage it and look forward and see what your forward view is as well. Okay. Perfect. Thanks a lot. Your next question comes from Robert Catellier of CIBC Capital Markets. Your line is open. I think you've answered the majority of my questions. Most of them are related to caps. But obviously, that's an asset that could help your GMP business generally. But that asset aside, what has to happen to get some renewed activity in and around some of the plants in dryer gas areas, simply a question of price? Or were some other assets in debottlenecking of the NGTL system help some of those plans? Hi, Robert. It's Brad here. I think, you've hit on basically the 2 key things. The certainly, the restrictions in moving gas to market, both through TCPL and some of the other egress points, have an impact on AECO pricing. And consequently, that has an impact on producers' willingness to drill or ability to drill the drier gas targets that are typically centered in the West Central region. I think for that reason is exactly why we've been enhancing our investment in growth in the Northwest part of the region where gas price becomes less sensitive. And certainly, as we look forward in time, the growth in volumes at Simonette and Wapiti and Pipestone are going to happen somewhat irrespective of what gas price is because they're so driven by the condensate side of the business, which remains strong. Sorry, does the recent round of NGL NGTL expansions add any market access capabilities to some of the dryer gas regions? Well, I think they all help. I think if you look out over time, the gap between AECO and Henry Hub is continuing to close. It's just a timing that says investments in NGTL often take a long time to kind of reach fruition. So consequently, that capacity comes on a little bit of time. And consequently, the growth or the ability to close that gap is slow to evolve. But we're certainly encouraged by the direction it's going. We're also encouraged by some of the additional opportunities that are being presented to grow internal consumption for gas as you look at coal conversions and things like that. All those help to unlock capacity getting gas prices a little stronger in Alberta. Rob, it's Dave here. I just would add one thing. In that West Central Alberta area, we've got a very well developed network, obviously. What I would say is that the gas in that area is liquids rich. It's drier perhaps than what you see in the Montney around Grand Prairie. And it doesn't have as much condensate in the liquids as propane and butane. And so seeing stronger gas prices, seeing stronger propane and butane prices, I think would all be helpful in that area. But the economics of the resource are very good. I think as Brad has pointed out, the challenge for producers has been that they just haven't had the cash flow to reinvest. And if we can see some recovery in those commodity prices, then I think that will lead to more drilling activity in that area. That's certainly what we expect. Your next question comes from Robert Kwan of RBC Capital Markets. Your line is open. Good morning. Maybe I can start with volumes on the G and P side. There's been significant performance differential for volumes, like Simonette are doing very well. And then as you mentioned, kind of the West Central stuff, not so great. I guess just overall, have you seen volume shaping into the first kind of call it 5 weeks of Q4? But as well, when you look at the plants where you've seen volumes come off, I guess in many ways, how much more is there to go just given this has been a trend for several quarters? I think certainly one of the things that we've seen and certainly the producers have been communicating is they do see stronger pricing in the winter. And I think even if you look at the AECO trends over the last while, we have seen some stronger pricing for periods. Every time there's a disruption, it tends to be a little bit variable. So there's a fair bit of volatility. But I think starting October 1, there was a strength in pricing and we actually did see some strength in volumes as producers started to try to capture winter opportunities. I think we're going to see that continue. I think producers continue to look at volumes and say, if I had volumes, I may have been holding off on tying them in and turning them on until the strength of winter pricing kicks in. So I think we're going to see some of those. What impact that has over the back half of the Q4 and into the Q1 is hard to say, but I certainly believe that there's going to be it will be a more positive situation than we certainly saw through the second and third quarter when the price variability was quite high. Got it. If I can maybe turn to CAPS, you mentioned you're going to hook into KFS. Is it going to be an open access pipeline? Are you looking only to deliver into KFS? Robert, initially the plan is to tie into KFS. But again, we want a competitive system and that means it's going to be an open access pipeline. Got it. Recognizing it was a while ago and the routes are different, I'm just wondering how are you marketing caps out to customers say differently versus Alps? Or can you just compare and contrast the two projects for us here? Well, I think in general, first of all, I think our producer customers and also the consumers of spec products would like a competing system. So I think that's 1st and foremost. We have to be competitive on our tolls, which we believe we are. But we are looking and offering some other maybe items that may be differentiating our pipeline and that might be relaxed spec on the pipelines as well. Okay, got it. Maybe if I can just finish, you had a comment on both in the MD and A and on the call on rail service and just working with the rail companies. Is that something where you're seeing issues right now or potential issues brewing? Or is that just a cautious statement given what we've seen for rail service call in the past year? I would say it's a cautious statement. It's something that's not 100% within our control. So when we see situations like that, we try to mitigate our risk as much as possible. So we are working with the railroads again to try to make sure that we get the best service possible. I've been told that both lines have done a considerable made a considerable effort to staff up and add a lot more power and have made some investments since last year to again help improve their service. Robert, this is Dave here. I'll just chime in. I think Dean and his team have been working very hard through this year. I think it's fair to say that some of the challenges we had in the Q1 with the railways caught us a bit off guard. Since then, we've worked with the railways, but we've also established some contingency plans on our side, so that if we do see a degradation in service, we have some options to try and mitigate the effect of that. So I think at this stage, I'm knocking on wood as I say this, but I think at this stage we're feeling a lot more confident going into this winter. Got it. And I guess just to be clear since in propane withdrawal so far you haven't had any issues getting that product out? Yes, that's correct. I think one thing that helps us with our propane egress is that we have 3 pipeline connected terminals that can export, propane. That'd be at Rimbey, at our Edmonton terminal and also our Joseph Bergh terminal as well. Great. Thank you. There are no further questions at this time. I will now return the call to our presenters. Thank you. At this point, that completes our 3rd quarter call. If you have any further questions, please give either myself or Kelvin Locke a call. Thank you for listening and have a good day.