Earnings Call: Q3 2019

Nov 6, 2019

Good morning. My name is Simon, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corporation Third Quarter 2019 Results 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. Ms. Lavonne Zdunik, you may begin your conference. Thank you, Simon, and good morning. It's my pleasure to welcome you all to Keyera's Q3 conference call for 2019. Joining me today is David Smith, our 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. As we released our financial results yesterday, the focus of our call this morning will be on our business strategy, operations, business development, opportunities and financing. After our prepared remarks, we will open the call to questions. I would like to remind listeners that some of the comments and answers that we will provide today speak of future events. These forward looking statements are given as of today's date and reflect events or outcomes that management currently expects. In addition, we are also going to refer to some non GAAP financial measures. For additional information on non GAAP measures and forward looking statements, refer to Keyera's public filings available on SEDAR and on our website. With that, I'll turn it over to David. Thank you, Lavonne, and good morning, everyone. Care delivered impressive financial results again in the Q3 of 2019, with each key financial metric well above our results from the same period last year. These results reflect the value of our integrated business and new capital projects completed over the last 12 months. Adjusted EBITDA increased 68% to a record $269,000,000 for the quarter, while distributable cash flow per share increased 39% to $0.85 per share and net earnings per share increased by more than 4 times to $0.71 per share. We are on track to deliver another year of record financial performance as our midstream services remain in high demand and our capital program is on schedule and on budget. Keyera currently has a significant capital program underway that extends secured growth out to 2022. To progress our growth program, we expect to invest between $800,000,000 $900,000,000 in 20 19 and between $700,000,000 $800,000,000 in 20 20, excluding acquisitions. A significant portion of the investment in 2020 relates to the Pipestone gas plant and the CAPS liquid pipeline system. With a strong balance sheet and payout ratio of 67% year to date, Keyera expects to fund its current growth capital programs without issuing common equity, aside from the existing DRIP program. Keyera has a history of disciplined capital allocation and investment decision making. We invest in projects that generate strong rates of return on our invested capital while maintaining a healthy balance sheet. We remain committed to this strategy as we continue to grow responsibly and generate long term value for shareholders. I will now turn it over to Brad to discuss our operations. Thank you, David. During the Q3, our facilities operated well, and we continue to advance our capital program safely. We completed several capital projects, including the Simonette acid gas injection system in July, a second water disposal well at our Wapiti gas plant in August, followed by the Simonette gas plant expansion and the North Wapiti pipeline system in September. With the North Wapiti pipeline system operating, a second producer is now delivering significant volumes to the Wapiti gas plant. We completed turnarounds at our Resinthia and Racinas gas plants in the quarter. And in October, we began a 6 week planned maintenance outage at AEF. This maintenance work is progressing exactly as planned and we expect to be fully operational by mid November. As a reminder, this maintenance has allowed us to defer our next full turnaround at AEF until 2021. In October, we shut down one of our fractionators at the KFS facility for some unplanned maintenance. Our operations and commercial teams worked closely together to ensure that there was no impact to our customers. The repairs are progressing well and we expect to be fully operational again by mid November. We do not expect this outage to have a material impact on our 4th quarter results. Even with all of our activity to date, Keyera is on track to deliver yet another year of strong safety performance. To date, we have invested over $700,000,000 in capital projects, completing 4 gas plant turnarounds and conducted repairs at both KFS and AEF without a significant recordable safety incident. At Keyera, we recognize that providing a safe and healthy work environment is an integral part of being a responsible employer, operator and a good corporate citizen. I'll now pass it over to Dean to talk about our business development opportunities. Thanks, Brad. As David mentioned, Keyera has a significant capital program underway that extends our secured growth into 2022. A significant portion of this investment focuses on extending our infrastructure in the northwestern Alberta to support developments in the liquids rich Montney and Duvernay. Wapiti Phase 1 was commissioned in the Q2 of this year, providing 150,000,000 cubic feet per day of sour gas processing capacity and 25,000 barrels per day of condensate handling capacity. In the Q3, we completed the Simonette gas plant expansion and the North Wapiti pipeline system. We also advanced the 2nd phase of the Wapiti gas plant and Pipestone gas plant. Once the Pipestone gas plant is completed in early 2021, Keyera will be one of the largest processing and condensate handling companies in this region. In the first half of twenty twenty two, we plan to connect our gas plants as well as other third party facilities to CAPS, our NGL and condensate pipeline system. CAPS enhances the integration of our business by connecting gathering processing assets in Northwestern Alberta to our liquids infrastructure assets in Fort Saskatchewan. With stronger integration, we can provide services more competitively to attract additional volumes to our gas plants, fractionators, storage caverns and condensate system. Our CAPS team has been diligently focused on land acquisitions and environmental consultations. As a result, we are on track to submit our regulatory application before the end of the year. We are committed to continuous improvement of our business to competitively position Keyera for both an extended low commodity price environment and a recovery. As a result, we are reviewing various alternatives to optimize our gathering and processing operations, which may include consolidating throughput volumes at certain facilities. Our goal is to improve the utilization and profitability of these facilities leading to lower per unit operating costs, higher netbacks for producers and higher margins for Keyera. With that, I'll turn it over to Stephen to talk about our financial position and strategy. Thanks, Dean. For the first time, on a trailing 12 month basis, Keyera generated realized margin of over $1,000,000,000 This realized margin reflects continued strong growth in our fee for service realized margin, which grew 18% in the Q3 of 2019 compared to the Q3 of 2018. In addition, our marketing business continues to be a strong contributor to our cash flow, generating record realized margin this past quarter, largely as a result of the strong market fundamentals underpinning the iso octane business. As we expect these attractive conditions for iso octane to continue, we are increasing our 2019 marketing guidance to between $321,000,000 $350,000,000 for realized margin compared to our previous estimate of $280,000,000 to 320,000,000 dollars Our new guidance reflects our belief that AEF will be fully operational by mid November. As 2020 approaches, we expect to see a continued ramp up of volumes and associated cash flows from our infrastructure investments in the condensate rich Montney area. In addition, distributable cash flow in 2020 will benefit from lower maintenance capital and lower cash taxes. In 2020, we are expecting maintenance capital between $35,000,000 $45,000,000 which is less than half of 20 nineteen's expected maintenance capital. This decrease is due to less activity in 2020 as we have only 2 smaller gas plant turnarounds planned. We now expect to incur 0 current income tax expenses for 2020 as approximately $1,000,000,000 of announced capital projects, primarily from the Gathering and Processing segment are available for use in 2019. For 2020 2021, a further $775,000,000 of announced capital projects in the Gathering and Processing segment are expected to be available for use. As of September 30, we have now invested $1,500,000,000 of our $2,900,000,000 current capital program, and we continue to expect to deliver a return on invested capital of 10% to 15% in 2022 2024 for the original capital program and caps respectively. Keyera continues to be well positioned to fund the remaining portion of this current capital program without issuing common equity apart from the DRIP and premium DRIP program. This is partly because our net debt to EBITDA covenant ratio was only 2.1 times at the end of September and partly because our 2020 cash flow available for reinvestment is expected to reflect the benefit of 0 cash taxes and lower maintenance capital. With that, I'll turn it over to David for closing remarks. Thanks, Stephen. Even with the challenges our industry is currently facing, we are optimistic about the future of oil and gas development in Western Canada. The world needs Canadian oil and gas to responsibly meet growing demand and transition to cleaner sources of energy. Canada is one of the most responsible energy producing countries in the world with significant resources that are amongst the most economically attractive developments in North America. With Keyera's strong values and integrated network of midstream assets, we are well positioned to be an important part of this evolution. I am proud to lead a team that wants to be part of this important change and is dedicated to serving our customers, maintaining the highest standards of operational excellence, caring for people and the planet and creating long term value for our shareholders. 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. With that, I'll turn it back to the operator. Please go ahead with questions. Thank you. Your first question comes from the line of Matt Taylor with Tudor, Pickering, Holt and Company. Your line is open. Yes, thanks for taking my questions here. You mentioned a volume loss from a customer next year hitting out margin by about $10,000,000 or so. Is that enough to shut down the plant affected and consolidate those volumes to offset some of that impact? Just curious to know the size of opportunity you're seeing from OpEx savings by shutting down more plants? Matt, this is Brad. So I think I mean, with that specific customer, that itself doesn't drive a shutdown of a facility. There's sufficient volumes to make the facility at Brazo continue to run. I think what we're trying to do is create an overall strategy to say how do we have the right amount of processing capacity available for the business that's out there today that provides operating cost savings to our producer customers and enhanced revenues for Keyera. So that work is still underway, but all these every plant is kind of under review from that context. Can you provide some context of kind of the type or quantity of OpEx savings you're seeing? Or is it still too early? I would suggest it's certainly too early to tell. I think, again, our goal is really to try to create a more efficient processing network reflective of the volumes that we see over the next little while, but also position ourselves for the future when we anticipate that drilling activity will resume and volumes will come back. So there's a balance there that we're trying to achieve. Great. And then moving over to marketing, it looks like you guys are storing the low cost butane to be consumed in 2020. Do you guys have enough space there to store the feedstock to use in the stronger summer demand months effectively making marketing margins better for longer? Hey, Matt. It's Dean Saniguchi. Yes, that's the great thing about our assets is that we have a lot of storage capacity at our KFS site. So while our facility is down, we're storing all that butane into our caverns into one of our caverns. So we have a lot of space to accommodate that. And yes, we will be using that butane feedstock in 2020. Yes. So effectively after even after the contract resets in March? Yes. We'll have some residual inventory that will last beyond March for sure. And one last one, if I may. Just can you provide more color on what happened there with the frac there and what needs to happen to bring it back online before butane contract discussions there in Q1? I know you mentioned customers were impacted. What's the financial impact to Keyera? So we just had a we had an operating challenge with 1 of our fractionation trains that we had to take down. By utilizing our network of infrastructure and our commercial teams, we were able to really mitigate the impact to all of our customers and the financial impact to Keyera will be minimal in 2019. Again, it's one of the great things about our assets, Matt, is that we have 2 fractionators on-site. So the other fractionators running full out and very well. And so we're continuing to fractionate the NGL mix. And again, the NGL mix that is coming into Fort Saskatchewan, that's beyond our one frac capacity we're putting into storage and we'll frac it at a later date when it's back on. Great. That's helpful. Thanks guys. Your next question comes from the line of Rob Hope with Scotiabank. Your line is open. Good morning, everyone. The first question is just it would seem that the market is concerned about Keyera acquiring some high multiple assets that could be in the market or are in the market. Generally speaking, without I guess talking specifically about opportunities, how would you look at M and A? And correct me if I'm wrong, historically, you've really focused on assets with discounted valuations. Could you go up the valuation spectrum? Hi, Rob, it's Steve. Thanks for that question. It's we've had feedback particularly in the last couple of years from investors concerned that we might make an inappropriate investment. I guess I would point to all the investments we haven't made, I think as evidence of the discipline that we continue to exercise when we look at things. I think that we're very cognizant of making sure that we keep a strong balance cognizant of making sure that we keep a strong balance sheet and we're very cognizant of making sure that the investments we make, make sense from both a strategic point of view and a return on capital point of view. We're always looking at organic growth opportunities and M and A opportunities, and we always look at it through that disciplined lens. I'm not sure there's much more I can say. All right. Thank you. And then how are you thinking about funding? You seem very comfortably below the 3 times leverage that you've targeted in the past. Absent new projects or M and A, when could you look to shut off the DRIP? Or could you even sell some non core but high value assets that could accelerate some delevering? Yes. Hi, Rob. Stephen here. Again, as David pointed out, we do value having a strong balance sheet. The credit rating is also credit ratings are also very important to us as well. And again, as you know, BBB, mid by both the BRS and S and P. And so again, as we look at our capital program or opportunities that might come in front of us, we just want to continue to make sure that we are financing things appropriately. And at this current stage of the capital program, a $2,900,000,000 capital program and almost a little bit over half spent. We do view the DRIP as a cost efficient tool to put the right amount of equity into that capital program. That said, we are cognizant that the market would like to see that DRIP program turned off or in general among peers. And so when we do see we're in a position where free cash flow is sufficient to handle our capital program, happy to consider turning that off. And again, I think the important thing is at the end of the day, we want to continue to grow shareholder value. And so again, we're always resonant about making commitments ahead of time. But that being said, we understand the desire to live within cash flow in that respect. In terms of the leverage, the it's important to note that, that $2,100,000 that we show in the balance sheet, that reflects the benefit of the hybrid debt deal that we did in June. As you know, that's a subordinated piece of debt. And so that comes into the ratios and obviously makes that lower for covenant test purposes, etcetera, that focus on senior debt. I just remind yourself and others that credit rating point of view, they do look at total debt as a whole as well. And so we're constantly just continuing to manage the balance sheet appropriately and get that right equity treatment as well, which is one of the reasons we looked at the hybrid for an appropriate financing tool. I appreciate the color. Thank you. Your next question comes from the line of Linda Ezergailis with TD Securities. Your line is open. Thank you. I'm wondering if you could maybe help us understand a little bit better, how you're approaching assessing these alternatives when in terms of facility and volume consolidation. At what point do you expect you'll be in a position to make a decision? And will it be evolving over time or do you think it'll be one big adjustment? And can you comment on how commercially flexible you are? My assumption would be that you are or would you require some sort of amendments to your commercial agreements with your customers to affect all the changes that you are considering? Hi, Linda. This is Brad. So, I think the changes that we're looking at, I think, are going to be strategically placed over the course of, I would suggest, the next 9 to 12 months most likely. And they've actually started as recently as Q4, where we've looked at consolidating our Gilbey gas plant into Rimbey and have effectively been able to do that here in the Q4. So that work is still underway and there's still activities happening to make this happen effectively, but we actually see a scenario where from Gilbey will all be effectively consolidated into Rimbey. Now what that does is we have to rework some of the agreements with the producers that are going through Gilbey today and make sure that their agreements cover going to Rimbey. But if they see value in what we're trying to achieve, They're all positive about what we're trying to accomplish. So we would see small activities like that continuing to evolve over the next little while. Yes. And Linda, it's Dean. We really like the situation and I'd use Gilbey as an example. It's a situation where we believe that we can offer better value, so better netbacks for our producer out of this and Cara will benefit as well. It will take a little bit of time to realize those benefits over the next year, but certainly long term we think it's valuable. The other thing is that if you look at Rimbey, it's one of our most efficient facilities and it's the start of our NGL value chain, because all the liquids from that facility and we have a field frac there are all pipeline connected into our Edmonton and Fort Saskatchewan assets. So again, that's just a great example of what the benefits of this consolidation program that we're looking at. That's helpful context. Maybe just looking a little bit more bigger picture at your opportunities, Can you comment beyond acquisitions as to where you're seeing the most opportunities in the energy value chain? And specifically with the closure of the Philadelphia Energy Solutions refinery in late June, has the business case improved to potentially expand AEF? Or are there other factors that still make you pause on that front? Overall, we still see more opportunities associated with our CAPS pipeline. So again, that could lead to more frac and storage investment in the future as we bring more liquids into Fort Saskatchewan. We're looking at the possibilities of maybe gathering and connecting to a pipeline into BC and collecting some of the volumes in BC and into caps and into Fort Saskatchewan. With respect specifically to AEF, AEF, the idea of AEF Twin is intriguing. And again, it's something that is a project that we continue to consider. And one of the reasons is, is if you look at octanes going forward, the gasoline blends are moving to a more environmentally friendly product, which is higher octane and lower RVP. And that's advantage that our iso octane has over alkylate. And so what we have is a premium product that nobody else makes and again with the brownfield site that we have, we can add capacity more cost effectively than anybody else. Okay. And when do you think you might be in a position to make a decision on twinning AEF? I think as we've said before, part of the challenges are is that we would want to make sure that we had enough of contractual underpinning with a third party to make sure that we're not taking more exposing ourselves to more basis risk than we'd want to in that even though it's very profitable business. That's helpful. And maybe as we just kind of look at other opportunistic infrastructure in Western Canada related to addressing some of the bottlenecks and issues there. Have you assessed the merits of potentially getting involved in a DRU or is that something that's not actively being looked at this point? Linda, we look at a lot of different projects and the DRU is something that we've absolutely looked at. I think it's one of those investments where if you believe that another pipeline will never get built again, it makes a ton of sense. You believe that you're going to get capacity pipeline capacity in Alberta then it's a much more difficult investment decision and especially to get someone to underpin it. Because it's going to take you 2 to 3 years to actually engineer and build it. And then you need another 10 or 15 year window to get your return on your investment. So it's a tough investment to move forward. And I'm not saying that it won't happen, but we've looked at it and that's sort of what we concluded. Linda, it's Dave here. I might just add that I think what you're hearing from Dean is a bit of a theme that we have a lot of opportunities in front of us that we're evaluating. But I think particularly in the current environment of uncertainty in our industry, we're not going to do anything on spec. We need to make sure that we've got the kinds of underpinnings from customers that make those investments make sense. Your next question comes from the line of Patrick Kenny with National Bank Financial. Your line is open. Yes, good morning guys. It looks like Wapiti Phase 1 made a strong contribution out of the gate. Just wondering if we can get an update on the drilling activity and volume growth that you're seeing around Wapiti as it relates to Phase 2 coming on mid next year. Do you see Phase 2 filling up as quickly as you had initially expected? Or do we need to see a bit more of a sustained recovery in AECO prices before Wapiti Phase 2 can be expected to achieve the low end of your 10% to 15% hurdle rate? Hey, Pat, it's Deane. Good question. Generally, we are very confident that will get in the range in the 2022 timeframe as Stephen outlined earlier. The ramp up is a bit slower than what we originally anticipated. And part of it is because one of our customers, the composition of the gas that they're producing from their pads is more liquids heavy. So we're seeing less gas at our gas plant than we originally expected at this point in time. Having said that, we believe that the production will normalize and the composition of the gas will be more like the type curves that we would expect. So that's part of the reason for the slower ramp up. And I think producers are just a little bit more cautious in terms of how fast they ramp up. But again, we certainly see a line of sight to getting within that 10% to 15% return on capital range in 2022. Okay, great. Thanks for that Dean. And then on Bellatrix, thanks for confirming the letter of credit you have in place there. But just curious how we should be thinking about the sustainability of the take or pay cash flows you have there as volumes naturally decline at the plant. Do you see any risk at all that your take or pay contract may not hold up in the courts? Or I guess conversely, if and when there's a change of control, do you expect you'll have to reset your fees to current market rates? Hi, Patrick. Yes, Stephen here. No, those are good questions. And obviously, we would like to continue to see the our producer customers continue to be healthy and strong, but Bellatrix was a situation that has come up as well. As you mentioned, we do have the LC in place to protect bad debts. Again, our current view is right now from our understanding talking with Bellatrix that they want to continue to work with us in a healthy manner at the Alder Flats plant, which is our main plant with them. We do have some operations at other volumes at other plants, but they're more less material, they're more minimal. And again, in these kind of situation, I think there's always the risk of take or pays potentially being removed, but the underlying desire to process volumes often is still there. And so a lot of times it involves just renegotiation of current things. I think that's where we may look at for some of those smaller volumes. But again, our current feedback to date is that they want to continue working with us at Alder Flats and it's been a good relationship between us as which again is a testament to the value of putting effort into customer relationships and so it's been good to see. Yes, I mean, I would reiterate, we do have a very good relationship with Bellatrix, and we're working with them. I think the other positive factor is that with the compression of the AECO NYMEX basis spread being a lot tighter, I guess in other words AECO prices firming up, that certainly helps in terms of Bellatrix's position as well. So we certainly feel pretty good about our arrangement right now. Okay. Thanks for that. And then on the other side of the customer spectrum, any thoughts on Encana moving to the U. S. Mainly as it relates to the returns you expect to generate from your Pipestone plant? Should we expect in Canada's throughput at the plant to come into the lower end of expectations? And now it's a matter of backfilling capacity with other producers in the area or is it still very much business as usual up there? Patrick, we are still getting the same sort of communication from in Canada that their plants haven't changed and specifically in the Pipestone gas gathering facility, processing gas facility. The other thing I'd mention is that that's a very attractive plant and part of it is because of the amount of liquids we can handle there. And there are other producers in that area that are looking for capacity as well. So if for some reason Encana were not able to deliver the volume profile that they have laid out to us, There's certainly other producers in the area that are looking for that capacity as well. Okay. Thanks again. I'll leave it there, guys. Your next question comes from the line of Ben Pham with BMO. Your line is open. Okay. Thanks. Good morning. I just wanted to continue the gas volume conversation. I mean, it sounds like Wapiti is filling up maybe a little bit slower than expected, but I mean, it's you still should see some growth there. And I'm wondering, you switched to maybe Central Alberta for a second. And when you kind of think about the past cycles of weak gas, you guys have done a pretty good job of working with customers, reducing costs, passing over and you've seen weak counterparties getting taken up by stronger counterparties. So I guess when you speak with your customers today and you look at next year, I mean, do you think this cycle will be different than the last couple that you've been through? And do you have to look at key renegotiations or these bankruptcies? I mean is this cycle do you think is going to be a bit different? Well, Ben, we I mean, I'm sure you follow the gas markets very closely. And on one hand, we feel very more optimistic at least about AECO gas prices moving forward and the basis bloat that we've seen over the last 24 months. Hopefully that's improving going forward because that's really hurt our producers in Central Alberta or in the Southern capture area. And so I think that's promising. But at the same time, we're not counting on higher prices. We have to continue to position ourselves so that we are as competitive as we possibly can be. And yes, sometimes we've had renegotiate summer contracts in some areas, usually to extend the term, so we get something out of it at the same time. But recently, even as recent as November 1, one of our producer customers brought back on over 50,000,000 a day of gas through our system. And that would be through the Braz, West Pembina, Nordegg sort of facilities. So we're already seeing a bit of response, but we're cautiously optimistic about what that looks like going forward at least in 2020. Longer term, we certainly are positioned for a rebound just like we saw in 2014. Okay. That sounds correct. Ben, it's Dave here. I might add, I think this cycle is different in how sustained the decline in drilling activity has been. I mean, we're now into the 6th year of very low commodity prices. And I think I would look at our track record over that 5 year period and say we've our volumes have hung in quite well considering the environment that we're in. And I think we've done we've continued to look at how we can be more efficient, reduce costs, enhance netbacks for our customers. But with the sustained lower drilling activity, we just think it's our responsibility to continue to look at those opportunities. And that's really what's kind of brought us to this point. The advantage, of course, that we have in this area is we have a very efficient network that's connected together with spare capacity that allows producers when we do see a recovery, it allows producers to bring their gas on quickly without a lot of capital. That's great to hear. And maybe my next question is for Stephen. The debt to EBITDA of 2.1x puts you in a really strong position. And I think a few quarters ago, you mentioned you didn't want to be above 3x. So my question is, do you just take the 2.1 at just, I guess, face value and you don't make adjustments to the hybrids and the marketing and you compare it to the 3 in terms of how you think about the financing outlook? Yes. No, it's a good question there, Ben. I think from our point of view, whenever we talk about debt ranges, etcetera, it's meant to be more of a long term sustainable view, given the portfolio that's in place. And to the extent that you put more and more assets in that are fee for service and take or pay that obviously gives you the flexibility to change your views. My earlier comment about the 2.1 was just to just help investors and research analysts to realize that just because you're at 2.1 on a ratio like that where subordinated debt brings that senior debt ratio down considerably. Just remember there's various stakeholders there. There's our own internal view about always having flexibility on our balance sheet to take advantage of opportunities. There are credit rating agencies who a lot of them look at more total debt kind of situation. And so we try and factor all those kinds of different factors in when we look at an appropriate range in terms of debt there. Okay. And maybe Hopefully that helps you. No, no, that's good. That's very helpful. And then on just close-up on the marketing. I know you upped the guidance this year and it looks like your run rate is pricing upside next year. I'm going to wait to see some color on that. But I just saw something, I think you're saying your market diastoctane, I think, is more than 50% of your cash flow is in marketing. I just want to, is that like your last 5 year average that's driving that calculation or is it something else that is that the inhibitor? Yes. I would say if you looked at our marketing over the last few years, we've had a very strong contribution from that whole butane to iso octane value chain. Again, we get to buy butane at market. And so if the market is lower as we saw in 2019, then we get to benefit, which provides that diversification on the other side when commodity prices are a little bit lower and affecting drilling. We do actually see isooctane is the majority of the contribution. Isooctane is the majority of the contribution. So it would be fair to say that, that would be higher as we went into 2019. It is a fair observation. Okay. So that's just to double check that. That's more than 50,000,000 that's you're saying more like a 200,000,000 run rate and when you have outside Yes. So if you look at that base rate that we put out there in terms of the $180,000,000 to 2.20 it's probably a fair assumption that it's close to the majority being from the isooctane business. And again, when we look at the marketing business, we view it as our whole goal is to we enjoy the cash flow from that, but we also try and take very conscious steps of mitigating any risk with that. And so whenever we have inventory in place, we hedge it. We're making our margin on the way through on the NGL products, on the isooctane value chain, when we see opportunities to lock in the margin then we along that whole value chain we try and lock it in. And so our whole goal really is to derisk that marketing cash flow while receiving the benefits of that whole system. That's very helpful. Thank you. Your next question comes from the line of Robert Catellier with CIBC Capital. Your line is open. Hey, good morning, everybody. I'd like to start with the Nevis shutdown. I think the plan there is to decommission. So can you give us some type of guidepost in terms of how much it might cost and how long will it take and whether that's in the capital budget? So Nevis Deconstruction and cleanup will be a multiyear program. So, it's going to take a period of the process is you have to get approval from the regulator on what your deconstruction plan and then you need to implement that plan. So, we're basically setting up the facility today to prepare for future deconstruction and it will be a very targeted low level of investment kind of over a longer period of time to get it to that final resting state. So in the end, on a total capital basis, it's not really that material in the overall scheme of things. As you look to consolidate some of your other plants, do you see any opportunity for others to be decommissioned? Or will they turn them into compressor stations or what's the plan? I think in the and certainly in the West Central region, the interconnected nature and the gathering system that feed into them really probably sets them up more along the line of a compressor station type scenario as opposed to a complete shutdown scenario. Nevis was unique in that it was standalone and didn't have connected facilities to it. So when there wasn't enough gas to keep it viable, you really have no choice but to shut it in. I think we have more flexibility in our other facilities in terms of how we can structure their operations and make them sustainable in the long term. Okay. And just turning to the marketing, specifically the butane market, prices recently have shot up. But if you look at inventory levels, they're very high in North America. So just if you could provide a little bit of color what your expectations are for the butane market in 2020? And how much of your current requirements are hedged or already in inventory? Rob, it's disclose against how much we have in inventory, but we are inventorying all the butane supply that we're purchasing now that's not being consumed at AEF while it's down. So again, we'll have that inventory that we'll be using throughout 2020 as our feedstock. That will certainly help the balances. Prices are higher today, a bit higher today than where they were throughout the rest of 2019. But they're certainly still very constructive to that isooctane business And where they ultimately land when we head into our re contracting season which starts in April 1 next year, that's undetermined, but it's certainly within an attractive range. Okay. And then the other side of the coin, of course, is the isooctane. Those prices look stronger, some decent premium. So do you think the risk between butane and isooctane are relatively balanced? Or how do you see the outlook from here? We feel as I said earlier, we feel pretty good about the demand for octane and particularly our iso octane. Again, it's the high octane count and low RVP that really makes it attractive. And again, that's the direction of where fuels are going. So we feel pretty good about where octane balances and demand is and our ability to satisfy that at a pretty good premium. Okay. You've answered my other questions, so I'll leave it there. Your next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open. Good morning. Maybe starting on the G and P business. I'm just wondering, can the work that can be done to streamline things into certain other plants, can that be done within the existing plant connections? Or if that's not the case, how much capital do you think might be needed to interconnect and expand that you need? Robert, this is Brad. So, I think that's part of the evaluation that's going on right now. There are certainly a lot of connections that exist right now that would allow us to move volumes around. But in order to make the most significant impact in terms of enhanced operating cost reductions, improved producer netbacks and improved returns for Keyera, There may be some capital investment in pipelines and additional connections, compression, those types of things to get those volumes landing in the right spot. But all in all, they fit very well within our program and each individual opportunity will be justified on its own merits. Got it. And there was a statement kind of as you were describing this earlier in the call around your expectation for higher margins for the company. Just wondering is that on an absolute basis or is it higher margins at specific plants? Well, I think there's again, it will be unique to each individual opportunity that we pursue. Ultimately, our goal is to not only to create efficiencies that reduce our cost to our producers that allow them to be more efficient and then potentially drill more wells behind our plants. But we also have to keep in mind that our goal is to enhance shareholder value. So ultimately making sure that the things we're doing benefit the shareholders of Keyera and which could be improved netbacks on a per unit basis is probably what we're trying to focus on is where we're going to be looking. Okay. And then from a KR perspective though, in terms of the higher margins, are you talking about dollar margins or percentage margins or both? I would suggest I mean, what we're trying to get is improved margins on a per unit volume perspective is what we're trying to achieve for both ourselves and our producer customers. Got it. Yes. Robert, it's Dave here. I'll just chime in. I think the way it's probably too early to provide any guidance. But certainly from our expectation, ideally what we'd like to do is try and more or less maintain the volumes at a lower per unit cost, which would benefit the producer in terms of higher netback, but also benefit us in terms of the per unit margin that we're earning at those plants. But it's a bit difficult to generalize because as Brad said, each situation is going to be a little different. Got it. Just I don't know if it's kind of G and P or just value chain, but with frac space being tight and getting tighter, just wondering if you can talk about the ability or the discussions you're having to prioritize producer volumes that are going through your gas plants and how that might help retain those volumes? Robert, can you maybe rephrase the question? We're not sure we understand what you're asking. Yes. I'm just wondering, I guess with the frac base being tight and if you think about Brazo River producer trying to pull volume or pulling volumes away from your plant, Are you having discussions with producers about prioritizing the volumes that are going through your gas plant as you head into the next NGL year to go through KFS versus processing people who want to do it a la carte? Well, I think our business, we try to look at it from both sides. So where we can offer an integrated suite of services to a customer that allows them to process through our plants and move liquids through our infrastructure and provide us marketing opportunity is certainly a desire that we have. That being said, we currently get a lot of volumes into our liquids infrastructure business that come from places outside of our plant. So I don't think we while we prefer the full value chain opportunity where we can provide that full suite of services, we're open to a variety of models in terms of where those volumes would hit our value chain. Yes. I would add Robert, I would add, I think your premise is correct that I mean our ability to be able to provide the full value chain of services gives us an advantage at the gathering and processing facilities. And I think certainly the customers that we the gathering and processing customers that we have at our plants can expect that we'll take care of their NGL volumes on a priority basis. As you know, we invested in the KeyLink pipeline 3 or 4 years ago, which allows us to more efficiently gather the liquids from those plants in that West Central Alberta area. We do have a couple of 3rd party plants that are connected to that system, but it certainly gives the Keyera operated plants in that area an advantage. Okay. And maybe just finishing with the U. S. Side and the Oklahoma liquids terminal in Wildhorse, but just on Oklahoma, it sounds like in the MD and A that performance is pretty good. I'm just wondering if you can give a few more details performance versus plan. And then as you think about WildHorse, has there been any change in your investment thesis or expectations given the Oklahoma Liquids Terminal performance? And just what you've seen more recently with the start up of some of the new pipes in the area? Hi, Robert, it's Deane. With respect to loyalty, it is it performed better than our expectations this year, so very strongly. And we have a pretty good outlook for 2020 as well. With respect to WildHorse, we still believe that that's going to be a very good business and generate strong returns and our views haven't changed. So it won't be up and running till late next year. So it won't have much impact on our results in 2020, but certainly going forward beyond that, we feel pretty good about it. But did you see the OLT performance as being transitory or do you see that kind of carrying forward and as you bring WildHorse and maybe makes WildHorse better? We think it's going to be a strong business. I mean, there's a lot of things that happen from year to year that could affect results. But generally, we think that it's going to be a strong business going forward. And we think that also applies to WildHorse as well. Great. Thank you. Again, we're just a little bit cautious. We have a very strong outlook for WildHorse, but we have to get it up and running and prove we can make money there. So we have to get it up running first. Got it. Thanks. There are no further questions at this time. I turn the call back over to our presenters. Thank you everyone for listening to our conference call. That brings it to a conclusion. If you're in Calgary, stay warm as it is minus 14 here. And if you're in Toronto, enjoy the sunshine. Thank you. Ladies and gentlemen, this concludes today's conference call. You may now disconnect.