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Gibson Energy Inc
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Good morning, ladies and gentlemen. Welcome to Gibson Energy's Second Quarter 2021 Conference Call. Please be advised that this call is being recorded. I would now like to turn the meeting over to Mr. Mark Chyc-Cies, Vice President, Strategy, Planning and Investor Relations. Mr. Chyc-Cies, please go ahead.
Thank you, operator. Good morning, and thank you for joining us on this conference call discussing our second quarter 2021 operational and financial results. On the call this morning from Gibson Energy are Steve Spaulding, President and Chief Executive Officer; and Sean Brown, Chief Financial Officer. Listeners are reminded that today's call refers to non-GAAP measures and forward-looking information. Descriptions and qualifications of such measures and information are set out in our continuous disclosure documents available on SEDAR. Now I'd like to turn the call over to Steve.
Thanks, Mark. Good morning, everyone, and thank you for joining us today. I'm pleased to say we delivered another strong quarter, both operationally and financially. As important, we made a lot of progress on the commercial front in 2021. And we've continued to integrate ESG and sustainability as part of our business strategy. Looking briefly at our financial results. Infrastructure adjusted EBITDA of $118 million was right around our $100 million target after normalizing some items that Sean will speak to. On the marketing side, adjusted EBITDA of $19 million was slightly higher than we expected. Importantly, our payout ratio of 73% remains near the bottom of our target range of 70% to 80%. Leverage of 3.2x is within our 3 to 3.5x target range. On the balance sheet, remains very strong, including being fully funded for all capital. On the operational front, we recently completed the construction of the DRU on schedule and, as important, within our initial capital range. I want to thank the entire team for all their efforts over the past 1.5 years. We did an excellent job throughout the construction progress despite the challenges brought on by COVID. And our plan is to keep our projects seem very busy. Many of you have noticed the meaningful improvement in our commercial outlook as we move throughout the year.In terms of recovering from COVID, I would say we're there from a commercial perspective. We continue to expect to deploy $200 million in growth capital this year, with almost all of it currently fully sanctioned, and we would expect to be at or above our $150 million to $200 million range in the next few years. We recently performed a review of our projects over the last 3 years, representing approximately $1 billion in capital, and we're very much in line with that 5 to 7x EBITDA build multiple range on actual capital and current cash flow. We expect our future capital projects to remain within this range, which means we will continue to generate very attractive risk-adjusted returns for our shareholders. So in terms of keeping that project team very busy, at the end of March, we announced a long-term terminal service agreement with Suncor, our principal customer at our Edmonton Terminal. As part of the agreement, we announced a sanction of a Biofuel Blending Project. This project is ESG-positive, and as it aligns with energy transition, which is an increasing number of our opportunities we're seeing, and I really like the 25-year term. We expect the project to enter service mid next year. On the tankage front, we are very pleased to announce the sanction of a new tank at Edmonton. With this tank, we welcome a new investment-grade energy customer to our Edmonton Terminal. We continue to be in discussions with other TMX shippers and continue to move discussions forward. We believe Gibson is very well positioned to support shippers on TMX, optimize producer netbacks to meet stream requirements and to optimize our customers' crew between Edmonton and Hardisty, without having to physically move that barrel. At Hardisty, we continue to progress talks with numerous customers with storage needs and continue to have interest with multiple producers and multiple refiners on the DRU. Given DRU, there is a new product, customers would like to see how the market develops. We've continued to see this as a complicated set of agreements and our time line for a second customer remains late this year or early 2022. Shifting to ESG. We were very pleased that our efforts continue to be recognized over the past few months. As part of their annual review, MSCI recently upgraded our rating to AA. This is the highest rating of any of our direct peers and represents the top 15% performance within our broader global industry peer group. We've also completed our midyear update of Sustainalytics, where our ESG risk rating moved into the low category. We are now ranked 4th out of 199 companies in refiners and pipeline industry and have the highest score among our Canadian peers. We also added both the S&P, TSX, Composite ESG Index and the Sustainalytics Jantzi Social Index. Our goal remains to be an ESG leader relative to our peers. Yet, we remain humble, knowing that ESG is a journey, and we need to continue to make progress every quarter. Earlier this year, we took a major step forward by setting ESG and Sustainalytic targets. Shortly after, we became the first public energy company in North America to transition our principal credit facility to a sustainability link structure. By integrating our credit facility and capital structure with our ESG targets, this demonstrates a clear commitment to achieving these targets through the balance of the year, our focus will be to work towards the ESG targets we set. Also, we continue to improve our disclosure. We recently made our second annual submission to CDP, and we expect to publish our first TCFD aligned report later this year. We feel we had another strong quarter. We delivered financial results slightly above our expectations, and we remain very well positioned going forward. Our infrastructure business remains solid. We are excited to have completed the construction phase of the DRU. We are in the startup phase right now and continue the expected place in service sometime in the third quarter. We feel very comfortable in our ability to deploy $150 million to $200 million per year without sacrificing returns. And we are pleased to, once again, be sanctioned projects in 2021 after a very quiet 2020. Marketing conditions are improving. So our business does not rely on it, our balance sheet is very strong, and we are fully funded and our dividend remains very well underpinned by our stable long-term infrastructure cash flows. I will now pass the call over to Sean, who will walk through our financial results in more detail. Sean?
Thanks, Steve. As Steve mentioned, another solid quarter from a financial perspective. Infrastructure adjusted EBITDA of $118 million was in line with our $100 million run rate outlook after normalizing for a payment received for the present value of the remaining term on a rail loading contract in the current quarter. This was the case of the customer exiting the marketing and logistics space rather than a change in their strategy or market outlook. As a result, we expect the decrease in our rail loading revenues will largely offset the partial contribution from the DRU in the third quarter. However, this could actually end up as an opportunity where we subsequently lease up the capacity and perhaps and up net-net being better off. Marketing adjusted EBITDA of $19 million was slightly above our outlook due to some strength that we saw at Moose Jaw right at the end of the quarter. Aside from that, the quarter materialized very much as we expected, where there was certainly an improvement in the environment relative to the last few quarters. In that context, opportunities in the crude marketing side were still limited relative to what we saw pre-COVID. So our strategy to build inventories that Moose Jaw paid off. In terms of our outlook for marketing, we would expect Q3 to come in fairly close to Q2 or between $15 million and $20 million in adjusted EBITDA. Well, that could put us at the low end of what is implied by our annual $80 million to $120 million long-term run rate, I think we would stop short of saying that we've returned to a normalized marketing environment. We typically see reduced asphalt demand at Moose Jaw in the winter quarters, and we'd like to still see stronger demand for drilling fluids, which is improving as well as more opportunities on the crude oil marketing side of the business before calling the market normalized. In that context, we could certainly see a couple of events in the next 5 months that get us above $80 million for 2021, but we don't have line of sight to those at this time. And that's fine, as we don't rely on marketing to deliver our strategy. Finishing up the discussion of the results, let me quickly work down to distributable cash flow. Interest costs were $13 million relative to $15 million in the second quarter of 2020. Refinancing our debt over the past 18 months has been a major focus. In total, reducing our run rate interest cost by nearly $25 million per year and leaving Gibson with, by far, the lowest weighted average coupon within our Canadian midsized peer group at just over 3%, while at the same time, having the second longest weighted average tenor. Replacement capital of $4 million in 2021 was below the $8 million in the second quarter of 2020, in part, because we did not perform a turnaround at Moose Jaw this year. For the full year, we expect to be approaching $30 million given the desire to perform some work that was deferred last year due to the onset of COVID. Taxes of $7 million this quarter were $5 million less than the second quarter of 2020, largely due to lower marketing earnings. Also, these payments were slightly lower in the current quarter relative to the second quarter of last year, as we continue to actively reduce the number of leased railcars in our marketing segment. And on a trailing 12-month basis, despite rolling off a very strong marketing contribution in the second quarter of 2020 due to additional infrastructure being placed in service, the benefit of the onetime payment and improvements in our cost structure between adjusted EBITDA and distributable cash flow, our payout ratio remained relatively flat at 73%, which is still at the bottom end of our 70% to 80% target range. Similarly, our debt to adjusted EBITDA also remained relatively flat to the second quarter at 3.2x, which remains within our 3 to 3.5x target. Speaking to our financial position, we continue to maintain a fully funded position for all our capital with ample cushion for additional projects and will remain proactive in having significant available committed liquidity. At the end of the quarter, we are $140 million drawn on our $750 million credit facility with $58 million of cash in the balance sheet. We also have $115 million of unutilized capacity on our $150 million bilateral demand facilities, implying over $0.75 billion in available liquidity relative to $200 million capital program. In that sense, very much years of running room. And in terms of being proactive, during the quarter, we again extended our credit facility to a full 5-year term, now maturing in April 2026. We are particularly proud to have been the first energy company, not only in Canada but across all of North America to move our principal credit facility to sustainability linked terms. From a finance perspective, this will, in no way, limit our access to capital, though we very much like that our interest rate will move up or down with our performance on the ESG linked metrics. In summary, a solid quarter. Results from the Infrastructure segment were in line with our forecast on a normalized basis. And as expected, the environment continued to improve for our marketing segment. From a financial perspective, we remain in a very strong position, being within both our leverage and payout target ranges, remaining fully funded with ample cushion and with significant available liquidity. And as Steve spoke to, the big shift so far this year has been the return to sanctioning new capital at our target 5 to 7x EBITDA build multiple. This underpins our view that our business continues to offer a strong total return proposition to investors with visibility to continued growth in our high-quality infrastructure cash flows and an attractive growing dividend, all while maintaining a very strong balance sheet and financial position. At this point, I will turn the call over to the operator to open it up for questions.
[Operator Instructions] Your first question comes from Jeremy Tonet from JPMorgan.
Just wanted to start off with the rail contract care prepayment. I was just wondering if you might be able to provide a bit more color on what's happening there? And just overall, I guess, demand for that service, how you think about the ability to backfill in this environment? It seems like differentials have somewhat widened out a bit. So just kind of curious for your thoughts on that.
Sean, why don't you take the first part of it?
Yes, absolutely. Thanks, Jeremy. Yes. So as I said in the prepared remarks, the payment was received for the present value, the remaining term we had on that. Term was through to the end of next year. So from this perspective, it's really somewhat of a unique situation where it was a case of a customer that was looking to exit the space rather than a change in their strategy or their market outlook. And given the term was relatively short, we thought it made sense to actually allow them to exit. It was actually take-or-pay contract. So the optionality wasn't actually there. As we noted in our disclosed remarks, discount rate -- or we would have viewed the discount rate as being relatively low, and so the upfront payment, we thought made sense. So I'm not sure if you want more details on that from a financial perspective, and then Steve can provide the back half.
And then, Jerry, as far as -- Jeremy, as far as demand, one of the great things about the DRU is, it really does create that 10-year contract for the HURC facility. And then we continue to load out trains and have continued to add trains from the facility. So the demand is still there, maybe not as great as it was at the peak, but there's definitely still a demand there, Jeremy.
That's helpful. Then maybe pivot into the DRU here. Granted, it seems like it's a complex process to sign up new customers there. Just wondering if you might be able to provide a bit more color with, I guess, the type of conversations you're having out there and they can take, I think, dozens of agreements. I think you said in the past and it takes some time. So just wondering, I guess, as you look out to these potential agreements, if you could give us more color on where those stand.
I would say our number one prospect there is they're wanting to see how this -- how the DRU went and how the DRU work, right? So once we've fully placed it in service how is that -- and that product starts to land down in the U.S. Gulf Coast, what is the value to that customer? And how smoothly does all of the transactions work? So really, that's really one of the things -- that's one of the hurdles we need to get over is getting in place fully in service, getting the products start to land on the U.S. Gulf Coast, letting people see and run those products in their -- that crude and the refinery. So we're still in the startup mode. So that's probably our number one. And then the other is a big refiner that we're continuing to have discussions with.
Got it. That's helpful there. And then -- maybe just the last one, if I could here. A similar type of question with regards to tankage, hearing what you're saying as far as commercial discussions really kind of kicking off in earnest earlier this year after kind of the COVID pause. And just wondering what you could talk about for new -- interest in new terminals at this point -- tankage at this point, especially, I guess, with TMX moving forward as well?
I would say, our major focus currently in growing tankage in Canada is around that Edmonton Terminal and supporting the TMX, the new -- the TMX shippers. So those talks continue just as we talked last quarter and continue to progress. And we do believe that we'll be successful and then adding additional tankage.
Your next question comes from Linda Ezergailis from TD Securities.
Just following up on your Edmonton tankage, can you comment on if you factored in any sort of inflationary pressures? And how those costs might have compared with some of your historical tank build?
Yes. I mean steel is definitely higher, Linda. But we definitely took that into effect when we were negotiating rates. And there's no different than any time you're negotiating contracts. It's really -- what does it cost to build the asset and what does that cost your competitors to build the asset. And then we had the minimal rate of returns and thresholds that we need to get across, which is at 5 to 7x. So it's really quite normal. The big inflation that we have seen is really -- when it comes to tanks is steel. So that's mostly all of it, it's steel, so and that has a reason.
Another follow-up, I'm wondering how much existing common infrastructure you're able to leverage or if you need to build out any of that as we think of sort of any -- sort of brownfield synergies or advantages?
Yes. I mean we definitely have some infrastructure that we're building in this first tank. And then additional tanks have some additional infrastructure that we want to get built. But the first tank definitely used a lot of common infrastructure that we have today. We're building it within an existing [ firm], really -- just really set up to build the tank, right? But we are building infrastructure with this project.
And just as another follow-up question on inflationary pressures being seen in the industry. Can you comment on your operating expenses and maybe if you're starting to see more labor costs? And with reopening maybe some of the cost savings with remote work dissipating a little bit? And any sort of other productivity initiatives, whether it be leveraging IT or other learnings from the pandemic net-net? How can we think, I guess, of your operating expenses trending prospectively?
I haven't seen inflation really start to hit us, but we're just now entering into the budget process. So that -- we'll know more about that kind of going forward. We haven't really seen an inflational impact to our OpEx currently. And definitely, our G&A is still down because travel is still significantly down. I don't know, Sean, would you -- can you comment?
Yes. No, I'd agree. I'd say inflationary, we really haven't seen a lot. And as you noted, Steve, G&A has been down. If you look at our OpEx specifically -- probably the only thing that has tweaked a bit higher in the past few months has been power costs for us. But again, that's not a material amount in the grand scheme of things. But normal inflationary pressure, we actually really haven't seen it yet. But as Steve noted, we're right in the teeth of budgeting right now.
Okay. And just on a separate topic, Interesting that MSC upgraded your rating recently, you've made a lot of progress in the past year on the ESG front with further initiatives pending. I'm wondering if you can provide some context as to how that might be translating into both your equity shareholder and debt holder mix potentially shifting? Are you seeing new investors coming in? Or are there more discussions with prospective new investors? Any context you can provide on that front would be appreciated.
Yes. Sean, why don't you take that?
Yes, absolutely. I think, as you know, Linda, we continue to make a lot of progress on the ESG side in general, be it our sustainability report, CDP submissions, recognition through third-party providers, sustainability linked loan. As I think of our shareholders, I think, generally, it has been very well received. Certainly from the generalist community, everybody likes what we're doing. They like the progress that we're seeing and that we continue to see in. I mean the journey is not over right now. From a pure-play ESG fund, we're not necessarily seeing a ton of incremental meetings per se from that. But I think thematically, just things are positive from that front. But I wouldn't say we're seeing a ton of pure ESG demand specifically. But I would say definitely from generalists or people that are somewhat a bit more focused on it, we are seeing positive momentum.
Your next question comes from Rob Hope from Scotiabank.
Two questions on the DRU. Just the first one and how it relates to the Hardisty rail facility. So you're going to have a little bit of opening capacity in '22 and beyond there. How do you think about that existing capacity? And how your other contracts roll off in the context of a DRU expansion? Like are you willing to take some open and potentially match that with an expanded DRU? Or would you look to optimize the rail capabilities if you are able to expand the DRU?
Well, I mean, when we talk about expanding the DRU, we talk about the potential to expand the DRU to 250,000 barrels a day. That's -- and why we say 250,000 barrels a day? Is that kind of the capacity of loading out this on DRUbit on the rail facility, the U.S. and [ G&S ] utilized. So I would say we would always -- we'd always lean to a DRU customer over a normal rail customer, that's just high grading your cash flows. It is -- I mean, if rail really comes back, we can certainly continue to expand the rail facility. But right now, we're looking to build DRUs and fill it with the DRU. And then we can link that 10-year contract on that rail terminal to the DRU.
All right. Appreciate that. And then just kind of a question just on how the market gains information on the DRU. So you mentioned that the customer you're in discussions with right now is looking to see how this all works and kind of the -- how it works through everyone's systems. But isn't your existing customer incented not to share that knowledge here? And how do you kind of educate the market on the value of the DRUbit barrel?
Well, it's the U.S. refiners, right? Right now, they get -- they're running deal bid, which is 35% to 40% condensate and then a really heavy neat bitumen. So -- and there's very little in between. So in states, if you're blending that, we would call that a dumbbell crew. And so refiner does it, they want a full carbon chain all the way across -- even carbon chain all the way across. So the neat bitumen or DRUbit gives them an advantage, the refiner, where they can actually blend it to maximize their refinery throughput. And so one of that -- the U.S., as you all know, continues -- its crude oil production continues to get lighter and lighter and lighter. Even with the -- they've even created new crude spec out of West Texas, West Texas Light, which is we would call condensate up here because it's 52 gravity crude. So once this neat bitumen gets in the market, we believe, and talking to refiners, there's an uplift in value over a deal bid. That's really kind of several dollar uplift in value over deal bid. So we want to -- and we need these customers who run it through their refineries and see how they like it and see how they blend. So that's really one of the main things we're looking to see.
Your next question comes from Robert Kwan from RBC Capital Markets.
Maybe I'll just start with the new Edmonton tank. And you talked about it being a competitive process, what do you think put your offer to the customer over the top?
I would probably -- I would -- it's our connectivity on this one customer, Robert. That was one of the things. And then I think just the relationship that our commercial people developed with that customer and the trust that they had that we would be able to fulfill all their operational needs.
Got it. When you talked about connectivity, were you talking about the inbound or the ability to put it out to the West as well as to the East?
This is probably an inbound.
Okay. Do you -- as you're talking with other customers around that Tankage, do you see that continue -- do you see that as being unique to this particular customer? Or do you see that something that you can leverage and do additional contracts?
Mostly unique for that customer. When I think about what -- how we can be competitive, I think the customer and I think we have a competitive price, so.
Got it. If I can just go back to the nature of some of the discussions you're having on additional contracts with the DRU, which as it relates to that first customer, have you basically or at least commercial side as well?
Yes. I would put it more in -- we've kind of agreed to all the terms. Now they need to make a decision whether or not they want to take that space or not. So yes, I would say, it pretty almost pins down and really do they want it? So kind of where we're at.
And whether it's this customer or the second or just others you're speaking with, is the scope really confined to a DRU expansion? Or would you -- or should we expect as well tankage at Hardisty to come with us?
I would say the second customer -- the kind of second leading customer, they would need probably -- it depends. They've talked about a pretty big appetite for the DRU, which could mean 2 -- 1 to 2 more tanks for them at Hardisty.
Perfect. And just a last question here. Just on the impairment, what was the nonperforming asset that you suspended operations at?
Yes, that was a treating -- a crude oil treating facility at our Hardisty asset. Sean, do you want to add some more on the color around that?
Yes. No, that's exactly it. It was basically crude oil treating terminal at our Hardisty -- or sorry, asset at our Hardisty terminal that basically wasn't cash flowing. So we shut it down and took the impairment -- noncash impairment as we have to.
Got it. And was that something that was previously contracted and rolled off? Or was that something that you kind of built for marketing purposes and just it wasn't panning out?
No, it was never a marketing asset, Robert. It was part of our old environmental business that did crude oil treating and really the need for that treating in the area, and it just evaporated. And we haven't seen any real business going across that terminal in the last probably 2 years.
Your next question comes from Chris Tillett from Barclays.
I guess just quickly for me. Can you give us an update on the spending in the budget for the DRU that's going into service now. CapEx was just a little bit light in the quarter. So kind of wondering if that's coming in under budget.
Sean, why don't you take that?
Yes. No, I'd say yes, CapEx was probably a bit light, but I mean we'll still have some CapEx as we continue the start up phase here. So as Steve said in his prepared remarks, I would say the DRU came in within our sort of capital budget. We are satisfied. We're happy with where it came in. As you remember, for our share, that was the $125 million to $175 million. So through last year and this year, it did come in. And then where we get to -- as you would have heard, we reaffirmed the $200 million for the year. But again, we announced a new tank today. We announced the Biofuels Blending Project. So that's sort of what gets us there as you think through the full year.
Got it. And then as we think through potential future capacity on DRU, is that sort of range for the first phase, a good benchmark for additional phases depending on capacity down the road? Or are there other factors that we need to be thinking about?
I mean the OpEx of that facility on the ground are probably going to be very similar to the first. There are definitely synergies in the control room. And the operators where we wouldn't need as many operators on the second facility. But as far as the DRU goes, we're excited about turning it over to operations. And operations is in the middle of start-up right now. And it's kind of normal. You have these operational issues. So we just got to kinks to iron out before we really announce that it's in full service, but we hope to get that in full service in a short amount of time.
And I think the other part of that question, if I heard it correctly, is cost for Phase 2, is that correct?
Yes.
And would it be a similar range to the first one? Yes. So what we've said previously is that a Phase 2 cost would probably be because of all the common infrastructure that we have built here, Phase 2 costs would probably somewhere in the range of 60-ish percent of what Phase 1 cost here. And so again, take advantage of the common infrastructure would benefit Phase 2, for sure.
Your next question comes from Robert Catellier from RBC (sic) [CIBC] World Markets.
Robert Catellier from CIBC World Markets. I just wanted to follow up on your comment there, Steve, on the DRU status. So what are the steps to achieving full commercial operations?
Well, we've met our 50,000 barrels a day range. And we've loaded out 2 or 3 railcars, maybe more. But there's just some fine-tuning that we need to do in the separation to get it to exactly where we want it, Robert. So the issues that the ops is working with right now is there's just some fine-tuning around getting that exact spec that we want.
Right. So that -- I take it from your disclosures, that's something you expect to achieve in the third quarter?
Yes.
Okay. And -- you've answered most of the other questions I have. Just one on the capital allocation. I wonder if maybe you can give an update where you stand on the outlook for share repurchases at some point on the one hand, I guess, marketing has been a little soft, although it's improving. You have seemingly very good one at sight, at least on getting the $200 million of capital spending and you're still in a pretty good financial position, but you have this onetime cash flow from the buyout of the rail contracts. So I wonder how that influences your view to share buybacks.
Sean, why don't you take that?
Yes. I can take that. I mean our thinking really hasn't changed. We do have that onetime payment, but it wasn't all that material in the grand scheme of things. As a reminder for everyone, capital allocation is first to growth capital to the extent that we continue to generate projects like we have 5 to 7x build multiples with investment-grade counterparties long-term contracts. Beyond that, and of course, we're going to remain fully funded to the extent we have excess cash flow, we've said if it's principally from infrastructure. We had favored dividend increases. If it's from marketing, we would favor buybacks. If you think about the messaging that we've put out for this year, it was -- at the beginning of the year, we put out a capital budget of $200 million and said to the extent that we do not achieve that $200 million, we would buy back shares to get up to that capital allocation. And that for us to execute a buyback, absent that, we need to see some form of material recovery in marketing back in towards sort of our run rate for the entire year. If you think about where we are right now, we're still -- we just basically announced today that we're almost fully sanctioned for the $200 million, so reaffirm the $200 million. So on that metric, certainly, nothing would change. And then from a marketing perspective, though we are seeing a recovery in performance, not really to the tune of where we would expect to change our thinking on a buyback. So as we sit here today, really not much of a change in thought for 2021. This is something we'll definitely reevaluate as part of our 2022 budget where we'll see what the capital outlook really is for next year as well, we'll have a view on sort of marketing performance for the year. One thing I would note on the buyback, though, is though we haven't used it all that materially, we bought back circa $15 million of shares in Q4 of last year. As a reminder to everyone, we did actually opportunistically call our converts for early redemption. Our shares had popped down below the conversion price for a very short period of time, and we are able to actually call that back for redemption, redeemed almost all of it for cash. When you actually look at when the converts would have converted normally, they were well above the conversion price once again. So not -- though not a formal buyback last year, we would actually view that as being somewhat fungible with having avoided the dilution through that. But the specific answer to your question is I think this year still, we're going to remain rather cautious because not a lot has changed, and that we'll reevaluate for next year.
It's a good point on the converts. And just with respect to the Edmonton tank announcement here. I wonder if -- are we at the front end basically of some contracts getting announced for the industry? The one thing that's not clear is that TMX and service date, they really haven't provided an update, that slightly believed to have slipped. So I'm wondering what the actual timing needs to be for contracting tanks to meet whatever the revised TMX and service date might be.
Yes. Hold on, Robert. We don't know the exact service date, either, Robert. But talking to our customers, it does appear that it has slipped. But we do believe that we probably have another 6 months of contracting opportunity before we would be late Edmonton tank in service. right? So we do believe it has potentially flipped, but we think as far as -- the negotiations really with our customers do continue to move forward. And right now, a lot of them are targeting kind of the end of the first quarter type start-up in 2023.
Your next question comes from Ben Pham from BMO Capital Markets.
I wanted to go back to the growth CapEx question, the $200 million budget that you have -- you mentioned a couple of the large projects supporting that number and the associated CapEx. But I think some of that CapEx is going to be spent outside of this year. So maybe can I ask what percent of your CapEx has been sanctioned of that $200 million as you sit here today?
I think 9-plus-percent. What do you think?
The vast majority of it, Ben. I mean we played around with the messaging do we say we're fully sanctioned to the $200 million or majority, but it would be, yes, the vast majority of that $200 million.
Okay. Got it. And then on the infrastructure side of things, you mentioned that as you hit the Q3, you get some prorated EBITDA from the DRU, and it looks like you mentioned it's offset by this rail contract roll-off. When do you think you can provide us an update on the new run rate for infrastructure, are you able to give us some sort of range today as you look at the puts and takes?
Yes. I mean I think -- I can take that, Steve. I mean I think we're already pretty much there if you just do the different math that we've given you already. So DRU, we've said $125 million to $175 million at the higher end of the 5 to 7 build multiple. And think of it that being sort of midpoint-ish of the capital. So that gets you to an approximate contribution from the DRU. And given it's a 10-year take-or-pay, you have that number on a quarterly basis. Q3, we've said that we -- the rail loading contract will offset the partial contribution of the DRU. Rail loading contract on a monthly basis is in around just over $1 million, so I think it's $1.1 million. So it's plus the DRU less the rail loading contract until we add additional assets into service. So for Q3, we think, as we've said, that probably in around that 100 is about the right number. And then Q4, clearly, it will be above that, because the DRU contract will more than offset the rail loading impact.
Okay. Got it. And then maybe on marketing. You mentioned that there's opportunity to be above $80 million, but you don't have the visibility yet. Would you say another side, you have enough visibility to make a comment that you won't be below, another range you've suggested that previously?
No. I mean if you think about the messaging we've given, so thus far, as we sit here in the first half of the year, we're -- call it, give or take, $22 million. Q3 guidance was $15 million to $20 million, which we had in our prepared remarks. So that gets you to -- for the first 3 quarters, $37 million to $42 million. I wouldn't say we're in a position right now to give Q4 guidance. If you use simple math of the $20 million to $30 million long-term run rate that we have historically had, that gets you to a range of $57 million to $72 million. And so I think what we are saying in the messaging we're trying to get across in the call today, is given that simple math, as we sit here today, we don't have line of sight for what could get us into that $80 million range. And again, so what that would take would be, call it, close to $40 million for the fourth quarter, given our current guidance. But it doesn't mean that there won't be events that get us there, which we have seen in previous periods, certainly as you think through sort of the '18, '19, '20 period.
Your next question comes from Patrick Kenny from National Bank Financial.
Just wanted to get your thoughts on renewable diesel here. It looks like there's at least one good-sized refining project in Saskatchewan that's making some good progress, another in BC. Just curious where your team might be at in terms of discussions with government officials and whether or not you see -- once the federal clean fuel regulations come together, supporting any potential opportunities at your Moose Jaw site, whether it be blending, terminaling or even refining and marketing of the product and the credits?
Yes. I mean I would say we're in the early stages of looking at that at Moose Jaw. We're looking at the cost to build a facility what at Moose Jaw would look like. We're taking a deep look at the feedstock and what are the -- out of the feedstocks work. And definitely talking to downstream customers on the renewable diesel side. Also, we are looking at what the -- the grant that could come from the federal government, so it is something that we're looking at. But it's still, I would say, very early stages, Pat.
And I guess that would be on top of the $1 billion backlog that you're looking at on the base business? And I guess, depending on what that grant looks like at this point?
I don't know about $1 billion backlog. I'd say it would definitely be in addition to any tanks that we have that we're guiding as far as capital going into the future. And it would definitely -- spend is over $150 to $200 million a year capital spend.
Right. Makes sense. Okay. And then sorry if I missed it, but just with the new tank being built at Edmonton. Maybe just a refresh on what's left in terms of remaining potential capacity at your Edmonton land position there. I guess, just how many more 400,000 barrel tanks could you potentially add ahead of TMX?
Yes. The facility, we can add almost 2 million barrels. So another just have been -- really the tanks that we're building are 482,000 barrels they're an odd size, but we can add just over 2 million barrels. So another -- there's space for another 4 tanks or close to 4 tanks.
Perfect. Okay. And last one for me, guys. Just with Alberta power prices more than doubling year-to-date, doesn't look like it's been a major headwind for your Infrastructure segment. But perhaps you could just remind us of any sensitivities that the business might have to higher power costs going forward? Or if you're pretty well covered by flow-through provisions within your contracts?
Yes, I wouldn't say we're covered with flow-through provisions in our contracts on power. But we're a very small power user. When you look at our ESG in our CDP report, our Scope 2 emissions is really quite small. And that's because we don't have big mainline pump. We don't have compressors, we're a pretty small power footprint overall.
There are no further questions at this time. I'll turn it back to Mark for closing remarks.
Thanks, operator, and thanks, everyone, for joining us for our 2021 second quarter conference call. Again, I'd like to note that we have also made certain supplementary information available on our website at gibsonenergy.com. As always, if you have any further questions, please do reach out at investor.relations@gibsonenergy.com. Thank you for joining us, and have a great day. Thanks.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.