Tidewater Midstream and Infrastructure Ltd. (OTCPK:TWMIF) Q3 2022 Earnings Conference Call November 10, 2022 1:00 PM ET
Company Participants
Scott Bowman – Director of Capital Markets
Joel MacLeod – Chairman and CEO
Brian Newmarch – CFO
Conference Call Participants
Rob Hope – Scotia Bank
Patrick Kenny – National Bank Financial
Robert Catellier – CIBC Capital Markets
Andrew Kuske – Credit Suisse
Robert Kwan – RBC
Micheal Simard – Private Investor
Tom Bauer – Pro Line Group
Operator
Good afternoon, and morning, ladies and gentlemen. Welcome to Tidewater Midstream Q3 Financial Results Conference Call. At this time, all participants are in listen on the mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call, you require for an operator. Also note that this call is being recorded on Thursday, November 10, 2022. And I would like to turn the conference over to Scott Bowman, Director of Capital Markets. Please go ahead, sir.
Scott Bowman
Thank you, and welcome, everyone, to Tidewater Midstream’s Third Quarter Results Conference Call. I’m Scott Bowman, Director of Capital Markets. And on the call with me today is Joel MacLeod, Tidewater’s Chairman and CEO; Brian Newmarch, Chief Financial Officer; and Doug Beamer, Tidewater’s VP of Corporate Finance. Before passing the call off to Joel to review some highlights, I just want to quickly remind you that some of the comments made today may be forward-looking in nature and are based on Tidewater’s current expectations, estimates, judgments and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which can cause actual results to differ from expectations. Further, some of the information provided refers to non-GAAP measures. To know more about these forward-looking statements and non-GAAP measures, please see the company’s various financial reports, which are available at tidewatermidstream.com and on SEDAR. And with that, I’ll pass it off to Joel Macleod to discuss some highlights from the quarter.
Joel MacLeod
Good afternoon to those of you out east, and good morning to those of us here in the West, and thank you for joining our Q3 2022 conference call. We are pleased to have delivered another strong quarter where we delivered $62 million of consolidated adjusted EBITDA in Q3 2022. This represents a 17% increase in adjusted EBITDA year-over-year. Business continues to perform well. We expect a strong Q4 and have increased our 2022 guidance as a result. We have increased our guidance for 2022 from $230 million to $245 million of adjusted EBITDA to $235 million to $255 million of consolidated adjusted EBITDA and do expect the strong performance to continue into and through 2023. Renewable [Technical Difficulty]
Operator
I am sorry sir. We can no longer hear you.
[Technical Difficulty]
Joel MacLeod
Can you hear us now?
Operator
Yes, sir. Thank you.
Joel MacLeod
Well.
[Technical Difficulty]
Operator
I’m sorry sir. You’re out again. Ladies and gentlemen, please stand by.
[Technical Difficulty]
Operator
Please proceed, sir. Thank you.
Joel MacLeod
Thank you. Can you hear me, okay?
Operator
Yes, sir. We can hear you.
Joel MacLeod
Okay. Sorry about that, everyone. I guess we dropped. We’ll take it back and start from the top just because they’re not sure where you lost us. So again, thanks again for joining us today. I apologize for the technical difficulties.
We are pleased to have delivered another strong quarter where we delivered $62 million of consolidated adjusted EBITDA in Q3 2022. This represents a 17% increase in adjusted EBITDA year-over-year. Business continues to perform well. We expect a strong Q4 and have increased our 2022 guidance as a result. We have increased our guidance from — for 2022 from $230 million to $245 million of adjusted EBITDA to $235 million to $255 million of consolidated adjusted EBITDA and do expect the strong performance to continue into and through 2023. Renewables business continues to outperform expectations in both adjusted EBITDA and distributable cash flow but do also want to highlight that consistent with the global economic environment, Tidewater Renewables is experiencing capital cost inflationary pressures as we resolve supply chain disruptions while adhering to the construction time line.
Tidewater Renewables expects gross capital cost to be approximately 10% above the previously announced guidance of $235 million. These incremental capital costs are not expected to have a significant impact on the HD RD complex’s economic returns as renewable diesel and BC LCFS credit prices continue to remain higher than previously forecasted. Management of Tidewater Renewables is taking these cost increases very seriously and personally. We continue to hold schedule and we will be commissioning will be commencing here in 90 to 120 days, where renewable diesel margins continue to exceed our expectations.
Further, Tidewater Renewables remains confident in delivering $150 million of run rate EBITDA once the HDRD facility is online. Again, I want to emphasize the HD RD project still expects to have an extremely attractive 2-year payback. We walk through the details of these cost increases on the previous Tidewater renewables conference call. Back to Tidewater Midstream industry activity continues to be extremely strong with 172 wells drilled at Pipestone, 97 at BRC and 68 at Ram River within a 25-kilometer radius of these facilities in the first 9 months of 2022. So again, near record high industry activity driving very strong volumes at all of Tidewater Midstream’s facilities. With distillate cracks, diesel is a component of distillate at 10-year highs.
The Prince George Refinery continues to deliver record cash flow and the timing could not be better for bringing on an incremental 3,000 barrels a day of renewable diesel in the next 3 to 6 months. During the third quarter, we successfully completed our financing plan to fully fund the repayment of our $125 million senior unsecured notes and $20 million second lien term loan. The notes and second lien repayments were funded through an equity financing, which included a public and private placement offering with total net proceeds of approximately $87 million and draws on our credit facility. As part of the financing plan, we increased the size of our senior credit facility by approximately 30% to $550 million with the facility maturing in the third quarter of 2024. Our current run rate debt to adjusted EBITDA is now in the 2.5 to 3x range, which positions us extremely well for the next 12 to 24 months. Over to Prince George, our Prince George Refinery during the third quarter of 2022, total throughput was approximately 11,860 barrels a day, consistent with the previous quarter.
Throughput has remained consistent with the previous 2 quarters as PGR nears the end of its four year turnaround cycle and operational constraints begin to limit some of our unit performance. All is going well at Prince George, and we do have a major maintenance turnaround here in the second quarter of 2023. Princor refining margins averaged over $85 a barrel during the quarter. That’s a 5% decrease from our multiyear highs in the previous quarter, the second quarter of 2022, where we saw over $100 a barrel margins or cracks. Consistent with the marginal decrease in the market, Prince George crack spread, PGR realized lower margins on both gasoline and diesel as compared to the second quarter of 2022. These lower margins are partially offset by increased gasoline and diesel sales as compared to both the previous quarter of 2022 and the third quarter of 2021 due to increased demand in the Prince George region.
We continue to produce numerous low capital, high rate of return debottleneck and optimization opportunities within our downstream business unit. In August 2021, Tidewater Renewables, that should be in August 2022, Tidewater renewables recently commissioned — or I guess, sorry, in ’21 was our canola coprocessing project, where yields of both renewable gasoline and renewable diesel continue to be strong. Tidewater renewables continues to test alternative low-cost feedstocks, including beef tallow through our FCC unit and canola coprocessing projects with initial results being very encouraging. As we jump over to Pipestone, so the Pipestone asset prior to its turnaround in September, the Pipestone gas plant processed volumes of 104 million cubic feet a day in the third quarter of 2022, a 6% increase from the third quarter of 2021 and an increase of 3% from the second quarter of 2022.
Facility availability for the second quarter of 2022 averaged 98% prior to turnaround, a 5% increase from the third quarter of 2021 and a 2% increase from the second quarter of 2022. The Pipestone Gas Plant turnaround commenced late in the third quarter and was successfully completed early in the fourth quarter of 2022. The local Montney formation remains very attractive and the plant remains fully contracted with over 80% committed capacity on take-or-pay arrangements. The activity in the Charlie Lake play as well continues to result in record liquids volumes through our facilities. We continue to progress Pipestone Phase 2 and evaluate financing and partnership opportunities. We’ll jump over to the Brazeau River complex, the BRC gas processing facility had an average throughput of 150 million cubic feet a day for the third quarter of 2022, an increase of 6% relative to the third quarter of 2021. The raw gas processing rates at the Brazeau River Complex increased by 23% compared to the second quarter of 2022.
Tidewater Midstream continues to look for opportunities to increase third-party throughput by working with producers to improve netbacks that would increase the utilization of the BRC facilities. — key announcement from Alberta Energy and the Alberta government, given that the 100-plus applications as it related to carbon sequestration, Tidewater Midstream was successful and was awarded 2 evaluation permits for carbon sequestration, one in the Ram River area and one in the Brazeau River area. If the evaluation demonstrates that the area is suitable for permanent carbon sequestration, Tidewater Midstream will be able to apply for the right to inject captured carbon dioxide. Tidewater Midstream and Tidewater renewables continue to receive material government support, and we expect this to continue through 2023.
Further, the volatility of AECO and related gas price has created material opportunity in our gas storage business, which outperformed in Q3, and we are seeing further outperformance in Q4 and expect this to continue. The Pipestone Gas Storage asset is ideally located for LNG projects off of the West Coast of Canada. Over to our subsidiary in Tidewater Renewables. Again, we saw performance adjusted EBITDA of $16.1 million and continue to expect to see our performance through Q4 and into 2023. Tidewater Renewables, our subsidiary remains confident in our ability to more than double our current adjusted EBITDA over the next 6 to 9 months with the commissioning of the HDRD project. Some quick highlights on the renewable side, signed a 20-year offtake with Fortis on RNG offtake; two, an Ameco credit facility, a 5-year senior secured second lien credit facility and a big thank you to the Aimco team. And three, we commenced FCC coprocessing early, which is a huge milestone and contributed to the outperformance.
Again, we expect Tidewater renewable to continue outperformance through Q4 and into 2023. And — and again, I would like to reiterate another strong quarter for Tidewater Midstream and do expect Tidewater Midstream’s results continue to be strong through Q4 and into 2023. I do want to thank our staff, Board, shareholders, credit syndicate partners and customers for all your support. I’ll pass it over to our CFO, Mr. Brian Newmarch, and he’ll walk you through the financial highlights of our Q3. Thanks again.
Brian Newmarch
Thanks, Joel. As Joel mentioned, Q3 was another strong quarter for Tidewater with consolidated adjusted EBITDA for the quarter of $62 million. As we outlined in this morning’s press release, strong operating performance of the PGR refinery consistent with consistent midstream returns about $16 million of EBITDA contribution from the renewables drove the financial results. A slight moderation of refining margins, combined with our planned turnaround at the Pipestone facility were the primary drivers behind the quarter-over-quarter difference in EBITDA. Pipestone came back on during the second week of October and refining margins have been strong through the first half of the first — of the fourth quarter and has led to a good start. Consolidated distributable cash flow attributable to shareholders was $9.2 million for the quarter and an aggregate year-to-date $62.5 million, which is a 25% increase compared to the previous period in 2021. The Q3 distributable cash flow number was slightly softer due to the softening in refining cracks and the maintenance capital associated with the planned turnarounds that we invested in during the quarter, and this distributable cash flow is a key metric for us.
During the third quarter, we completed a number of transactions to pay down $145 million of senior unsecured and second lien notes that were maturing in the fourth quarter of 2022, as Joel mentioned, — as we all know, this has been a very tough year from a macro perspective with the war in Ukraine, the inflationary environment, rising interest rates and the broader equity market weakness, making a refinancing a role of our debt maturities a lot more costly and more difficult to execute than the previous periods.
Ultimately, we felt the combination of equity and an expanded senior credit facilities to repay the notes was our best path forward. It was not an easy decision to raise equity and dilute existing shareholders. And we believe that the enhanced balance sheet provides a stronger base to support the growth that will help drive long-term shareholder returns and reduce interest expense in the raising rate environment we’re currently in. Following the refinancing transaction, as Joe mentioned, total debt was reduced by $87 million, and our leverage levels, as measured by our trailing 12-month debt-to-EBITDA metric is now below our 3x target. Turning to guidance. As we outlined in this morning’s press release, we increased our EBITDA outlook on a consolidated basis to $235 million to $255 million, and that’s a function of the strong performance within renewables that Joel spoke to, and the fact that our midstream business is tracking towards the higher end of our originally guided $180 million to $190 million.
From a capital investment perspective, we are expecting Tidewater Midstream’s maintenance capital to be approximately $5 million higher for the year and have adjusted our outlook from $35 million to $40 million to $40 million to $45 million for the year. This increase primarily relates to our Q3 turnaround work in the third quarter at the Pipestone facility that is now back online and processing gas rates at forecast levels. So this year, we’ve undergone 3 major turnarounds in the last 6 months with our midstream business — with our midstream business generating the EBITDA impact that has been offset, the midstream business had its EBITDA reduction slightly offset by the gas storage assets that have performed very well in the volatile a cash markets we’ve seen over the summer and into the fourth quarter. The weekend on some day’s negative ACOE cash prices and our Dimsdale storage asset advantage location in Northwest Alberta has allowed the team to capture additional value outside of the hedge summer winter Intrinsyc spreads.
With our turnarounds behind us, our gathering and processing assets continue to provide the steady run rate EBITDA, which, combined with our refining assets led to another strong quarter. With that, we will open up the call to Q&A. So back to you, operator.
Question-and-Answer Session
Operator
Thank you, sir. Ladies and gentlemen, if you would like to ask a question at this time, simply press star phone. You will then hear a 3 to home prompt acknowledging your request. And if you would like to remove yourself from this question queue, you will need to press star 2. And if you’re using your speaker phone, please lift the handset before pressing any keys — and your first question will be from Rob Hope at Scotia Bank. Please go ahead.
Rob Hope
The first question is on the Pipestone expansion. Just want to know where we are in the process of the evaluation. And then listening to the LCFS call, it did look like you were shying away from what would characterize larger projects, which I would imagine any of the Pipestone expansion would be during this inflationary time.
Joel MacLeod
Yeah. Hi, Rob. Joel here. So I would say we continue to progress Pipestone. We’re working through our financing plan and/or related options, but it continues to progress and I want to be clear. I think on the renewables conference call, that relates to renewables, given they’re in a $235 million project, which has now gone to $250 million to $260 million. And even the contract profile of renewable diesel is different of a 10-year take-or-pay back Pipestone expansion. We just built Pipestone Phase 1, and we’re looking to essentially copy and paste what we built up there. So I would say the comparison of renewable diesel to a Pipestone Phase 2 and the related risk is not comparable just given we just built Pipestone 1, find the copy and paste, build the 2 and have plan to have 10-year take-or-pay agreements in hand, but good question.
Rob Hope
All right. Appreciate the clarity. And then maybe along similar lines there. How are you thinking about the organizational breadth and ability to go after a number of projects at the same time? LCFS has a number of follow-on projects after the renewable diesel plant. And in midstream, it’s a little quieter right now, but you can have Pipestone some carbon stuff. How are you thinking about the ability to balance growth at Tidewater Midstream as well as LCFS?
Joel MacLeod
Okay. It’s a really good question, Rob, and some we talked to both boards here over the last few days. As I think we’ve relayed over the years to try and have 2 or 3 large projects going at the same time, especially in an inflationary environment is something we wouldn’t want to do as far as 3 large projects. So I think 2 large projects is our maximum, especially in an inflationary environment in the past. — with the Pioneer Pipeline in Pipestone Phase 1, both $200-plus million projects being delivered essentially on time and on budget. I think we’ve shown we can do that. But to your point, we have to stay focused, and it’s great that we have multiple capital projects, some of them 2- to 3-year payouts, some with contract profiles, and we have to just allocate capital accordingly. But can assure from both Board’s perspective, we have to be very selective with our capital and again, highly unlikely we would try and tackle 2 large projects at a given time. At the same time, realize the renewables team is now 35 where at the IPO, it was 2 to 3 and the midstream team is in the 450 staff members. So we are set up to have, I would say, each entity running to sizable projects at a time. But obviously, in an inflationary environment. Capital discipline here is critical. And the great news is we have lots of capital projects that are competing for capital.
Rob Hope
All right appreciate the clarity. Thank you.
Operator
Thank you. Next question will be from Patrick Kenny at National Bank Financial. Please go ahead.
Patrick Kenny
Thank you. Good morning. Yes, maybe just to come back to Pipestone Phase 2 and I guess in light of the 10% overrun on the RD project, would that 10% uplift be a fair proxy to the previous budget for Phase 2 here, which I believe was around $240 million, so call it now somewhere in the $265 million to $275 million range. And also, maybe you can just remind us from a commercial perspective, if those 10-year commitments that you had in place with customers have any capital cost flow-through provisions just in order to hold the economics of the project intact? Or maybe there are some other ways that you can mitigate the compression on returns from any increase in CapEx?
Joel MacLeod
Great questions, Pat. We’re very transparent with our customers. So we do expect to see the potential for fee increase with the increase in capital. We are closer to, I would say, all in $300 million of — and if we include fee increases that most of our customers would be comfortable with, we’d be in the $50 million of EBITDA range. So again, we are not FID-ing today. We are not at a point where we’re going to pull the trigger, but high-level numbers, $300 million of gross CapEx, $50 million of EBITDA and still some work to do through the project, but continue to progress.
Patrick Kenny
Okay. Great. Thanks for that Joel. And then maybe just from a funding standpoint as well. I know you can’t provide too many details until a deal is finalized. But just curious, given the increase in interest rates, no doubt, leading to a higher cost of funding from the financial players out there. But does that — does the current interest rate environment cause you to lean maybe more towards partnering up with a static player in the region? And if so, just curious what operational or value chain synergies would be most of interest to you as you look to expand the Pipestone franchise over time?
Joel MacLeod
Yes, it’s a great point, Pat. We would agree. We’re definitely having discussions with potential partners. Again, we’re not at FID, but continue to progress. And in this environment, even it’s been a very clear message from our Board, we need to continue to have a strong balance sheet. So yes, we need to evaluate the partner discussions. And to your question, what types of partners are interesting, I think, strategic where they can add value. I want to be a little careful because I think even the AMCO transaction, one example, we’re not speaking to Amcon Pipestone, but to see AMCO as a partner in renewables at that cost of capital is very interesting. And then some of our peers were customers. We work with almost all of our larger peers, and I would say there’s interest from some of those players and we work very well with, I would say, all of them. So I think all are on the table in discussions on multiple fronts.
Patrick Kenny
Okay. Thanks. And then last one for me, if I could, just to actually shift gears a little bit to ESG. I just saw some headlines out this morning, I guess, coming out of COP 27 with respect to how Canada might look to cut methane emissions by 75% by 2030. I’m sure you need a little bit of time here to digest the proposed regulatory framework, but just curious if you had an update on what still needs to be done across your midstream asset base to meet these targets? And then also maybe what new infrastructure opportunities might be out there with respect to helping your customers meet their methane compliance requirements as well?
Joel MacLeod
Yes, Pat. I think the Alberta government selecting us for those two carbon sequestration hubs, where our understanding is they had well over 100 applications is significant for us and our customers to be able to sequester CO2 bring down emissions. Even those reservoirs at Brazeau are gas storage. So methane does go down hole today. We have wells we have infrastructure as well. So I think it’s — step one is understanding all the related components to the CCUS hubs. We’ve been selected for two, but I think they offer great opportunities for both ourselves, our own emissions, but then also for our customers. And I think at what we do today .And I think from what we do today, we inject methane into multiple gas storage reservoirs. The infrastructure is there in place. We’re probably set up as well as anyone to help with methane emissions going downhill. And as far as that, we control.
Patrick Kenny
Perfect. I’ll leave it there, guys. Thanks.
Operator
Thank you. Next question will be from Robert Catellier at CIBC Capital Markets.
Robert Catellier
Hi. Just a couple of follow-up questions on that last one. So understanding that you do have existing asset gas injection assets in the company. Do you feel like you have all the required in-house expertise to develop those two carbon sequestration hubs? And related to that, most announcements we’ve seen from the industry involve partnerships. So any thought to partner in a project like this?
Joel MacLeod
Absolutely, Rob. Given the likely size and scale of the projects, we would need a partner to develop these assets. And again, our balance sheet remains paramount and critical. And we need to remain and we will remain in this 2.5 to 3x debt-to-EBITDA range. So I think it either requires a massive amount of government support or a partner. And we do consider the government, both federal and provincial, multiple provincial jurisdictions now with the support they’ve provided as partners. So we’re excited to your point. I think your question was on kind of AGI or infrastructure, our expertise. I think if you ask around even North America, Western Canada, given we have sour plants, we have a meat and we capture CO2 today, we drilled what I believe are two of the longest total-measured dePAGIwells, which have performed incredibly well.
And then we’d be a top 5 natural gas storage player within Western Canada, given our multiple gas storage pools, our reservoir knowledge. I mean we’re always humble, but I think if you ask around, we definitely would have the technical expertise, and I think have proven that given our operations and execution to date. Is it a big focus? I’d want to be careful. Now the carbon hubs today are not a big focus or large projects, and we need to understand the rules from the government. So we’re talking about 2, 3, 4 years out and even need another 6 to 12 months before we have any sort of feedback on economics and how we plan to attack these projects. So I think just give us 6 to 12 months and hopefully, we can provide some real information where now I would just say, Rob, are waiting for essentially all the rules related to CCUS in Alberta and across Canada and the incentives. We do think there could be more incentives coming especially from the federal government.
Robert Catellier
Okay. With that in mind, knowing it’s early days, and there’s a lot we don’t know. How much do you envision spending just on the evaluation of the poor space that you’ve been allocated?
Joel MacLeod
Just internal time, Rob. So I would say no capital outlay plan for now. We have the in-house expertise. So that’s just man-hours. So no incremental capital, no increase in leverage related to any of this evaluation. It’s our own know-how and staff and understanding those agreements, which is, again, in-house legal counsel in-house. Even our land department as far as understanding the mineral rights related to CO2 poor space. I don’t think I’m allowed to disclose that the dollar amount related to that poor space, but it is very minor and immaterial, which is great to be able to potentially lock up large positions of CO2 poor space and be selected for minimal capital is a material win for us.
Robert Catellier
Okay. Thanks, guys.
Joel MacLeod
Sure, Rob.
Operator
Next question will be from Andrew Kuske at Credit Suisse.
Andrew Kuske
Joel, you mentioned earlier, just a lot of the activity levels and how they’ve ramped up around some of your facilities. And I guess this is kind of a tricky question because some of the well type curves have notoriously quick decline rates before they level off. And so I guess maybe where do you think you are in that process from a customer standpoint of having flush of volumes come at you may be greater than you anticipated before it comes down to more reasonable levels. And then obviously, there’s a bigger question of what’s the activity levels in the future years. But maybe if you could just give us some context to start off with that.
Joel MacLeod
Yes. It’s a good point, Andrew, and we enjoy pulling data. I haven’t had a lot of time to pull the data and review with even some of our reservoir through a gas storage team. But the Montney, I would say, and Brian would probably have a sense coming from Seven Gen, but it’s definitely further on if it’s in the fifth or the sixth or the seventh inning, whereas the Charlie Lake around our assets is still pretty early. So to your point, decline rates are significant in both the Montney and Charlie Lake. But for me to tell you I know exactly where the decline lights or even for us, it’s more NGL and liquids yields as well, H2S, obviously, percentage is coming into our facilities, but we’re definitely seeing increased activities. So I think more work to be done but confident, especially in that pipe zone area, you’re going to see more volume. And every day, we have 5 to 10 producers looking for even 1 million cubic feet a day of incremental throughput. We’re running at $104 million, $105 million a day.
So there is definitely a shortage of sour gas processing up at Pipestone. And we think that, that is likely to continue because it remains difficult to permit and build and in an inflationary environment. So Pipestone, I would say, more volumes coming and we’ll be confident there. When we go down into Brazeau, there’s — I feel there’s definitely enough data. When we look at the Mannville, the notice and the flare, — we’re seeing a few Wilrich wells being drilled. — around us and the Cardium isn’t as gassy, but the Cardium, they’ve been drilling horizontal wells down there for 10, 12 years. So I would say we definitely have a large enough data set and history around Brazeau. Rock Creek would be one formation that they’re drilling and getting more oil. And I would say it’s way more variable than some of those other formations. But I’d say overall, if gas price remains at, you’ll know the curve better than I, about 450-ish AECO through ’26, ’27. We do expect volumes to tick up around Brazeau and RamRier.
And then maybe just to add to the one of the Montney commentary specifically, Andrew. I think point well taken around development activity and type curves that you have a better handle on than we will. I think the other 2 points that get us excited is, obviously, the expansion on the Enbridge system or the West Coast system that’s going to just create incremental pull on gas from the region and then obviously, LNG Canada over time here. So there’s going to be a pull, we think a lot of the development and the supply to tite those incremental pipeline flows will be in the ZIP code that we have assets in and I think is just a good place to be in the long run.
Andrew Kuske
Okay. That’s very helpful. And then maybe just coming back to some of the incentives, and Joe made the comment about there may be more incentives coming. And I think if the federal government’s tone on leveling the playing field with the inflation reduction act in the U.S. kind of hold true, looks like we will get more incentives than were incentives last week in the economic update, maybe more coming before the end of the year. How does that play into your calculus of CCS in the future and just some of the other things you’ve got going on in the hopper?
Joel MacLeod
Andrew, I think we want to see them. So we want to see, but I’m quite excited with what we’ve seen. We’ve never planned a business around government support, but the support we’ve received in renewables with $120 million now of grant support cash grant on a $235 million project is obviously massive, and we continue to see both federal and provincial government support. So we’re excited, but we need to see the rules, but it does sound like we are going to see incentives for CCUS and/or hydrogen. And for us to have natural gas feedstock, gas storage, gas plants and the Alberta government, even 1.5 years ago or so awarded us, which is public a significant grant in one of the largest grants. It’s great to be near the front of the line for the government support. But I think we just want to make sure we understand the rules before we come out with economics or excitement and our Board definitely wants us to be very selective and diligent with capital deployment.
Andrew Kuske
Okay. That’s great. Thank you very much.
Joel MacLeod
Thanks, Andrew.
Operator
Thank you. As a reminder, ladies and gentlemen, if you would like to on — and your next question will be from Robert Kwan at RBC Capital Markets. Please go ahead.
[Technical Difficulty]
Operator
Please go ahead Mr. Kwan. Mr. Kuske.
Andrew Kuske
Kuske I think it’s for Robert.
Operator
Robert? No. I’m sorry. We have Andrew Kuske on the line, I apologize. Are you finished?
Andrew Kuske
Yes. No, I’m good. You can go to Robert.
Operator
Okay. Robert Kwan, RBC.
Robert Kwan
Right. Thank you. Good morning. If I can come back to Pipestone and the commercial agreements. Just at a very high level, is there anything that’s binding the customers to you or you to them? It sounds like it’s not completely set, and you can still move your fees around to reflect the current environment.
Joel MacLeod
Correct, Robert. Still flexibility as we work through our plan and our customers have been phenomenal, and we continue to work extremely hard for them to try and find a solution.
Robert Kwan
Okay. And it sounds like based on what you put out there, the build multiple for Pipestone is a pretty good spread. So you’ve got that headroom. But just in general, as you think about holding an EBITDA build multiple constant, and that’s great. But as interest rates rise, that erodes equity returns, which is really what matters to shareholders. So how do you think about kind of your target build multiples given we’ve generally thought of them as EBITDA valuations given the interest rate environment that’s been rising here.
Joel MacLeod
Yes. Robert, you hit it on the head, and that’s where we feel we need to bring in a partner to bring our returns up. I would hate to give you a specific number or metric, but we have to be a 6x build multiple. And Brian, I don’t know if you want to jump in and add. That contract term is important, but the inflationary environment we’re in, we have to improve our economics and our Board’s asked us to do that. So that’s what we’re working through as we speak.
Robert Kwan
And is that the primary then risk mitigation, just trying to reduce the capital exposure? Because one thing you said, Joel, is that you view this as being different than what renewables has and I get the commodity side versus the take-or-pay, but in many ways, if you get it wrong under a 10-year take-or-pay, you’re basically wearing the return for 10 years too with no way to get it back.
Joel MacLeod
Yes, It’s a good point, Robert. The good news is pipes on Phase 1. We built it. We have our contracts. We’ve seen the cash flow and the free cash flow after operating that asset now for 3 years. So I would say we have a sense of how we want to contract the asset, no material changes to Pipestone Phase I — but to your point, our return threshold, and you know our trading multiple and our cost of capital is not what our peers are. It’s our biggest struggle, so we have to find a way to improve our return, and that’s what we’re focused on and our customers have been incredibly supportive.
Robert Kwan
Got it. If I can just finish with the producer activity and the volumes you’ve seen coming through the facilities. Can you just talk about what the remaining upside as you think about your available capacity, but take-or-pay isn’t really going to help you, but where do you have fee-based upside in your facilities? And then just generally, as the volumes have grown, have you seen more contracting, whether that’s resulting in just a greater level of contracting, fees moving up or just longer contract duration?
Joel MacLeod
Yes, for sure. And as you are aware, all our assets are a little different. Pipestone. Every 1 Mcf is highly competitive and fees can be harder. And I know although our facility is fully contracted, we are seeing more liquids volumes being trucked in C5 in particular to that asset. And then caps coming online here in the next 6 or so months, we’ll have the ability to also likely get volumes on cap. So that incremental volume gas processing at Pipestone is court absolutely, but the more liquids associated liquids we can move is definitely of interest to us. As we move down to — so our contract term, I would say, on liquids, 1-, 2-, 3-year type deals as far as trucking where gas processing as you’re well aware, is 10-year take-or-pay.
As we move down to Brazeau, definitely. We haven’t seen this activity in 7-plus years, but I would hate to say producers are ready for 10-year take-or-pay agreements. It’s more discussions on 2, 3, 4 year. And as our peers group care, in particular, as our competitors’ plans fill and we fill at Brazeau, there is potential that we can start to look at 5-year take or pace, which would be great, but also our real focus right now is bringing fees up to what we would say is more market, given the cost to do business, OpEx, maintenance CapEx has all moved up. And I would say fees are definitely moving up even down at Brazil and do feel that will trickle into ramp. So where do we have incremental upside or underutilized capacity. The largest asset would be RAMbrazeau, you’ll see — I think we show 150 million cubic feet a day here in Q3. So we are getting fairly full, just realize there’s still an extraction component where we straddle volumes and Sanan to TransAlta and PIONEER.
So our goal will be to increase the related margin and bring in third-party and back out some of that straddle piece that’s moving on to TransAlta. — keep the plant full. And yes, we have 5 million or 10 million a day of Brazil to fill the plant, but increase the margin will be our goal at our facilities. I hope that answers your question.
Robert Kwan
Yes. That’s good. Just if I can on that fee side of things, Joel, how material is that? Is that something where you could add just as fees are creeping up? Is that something that’s single-digit EBITDA on an annual basis? Or is it more?
Joel MacLeod
I think today, we would say single digit, Robert. But if you had to view gas prices are going to be $5.50 over the next — even in the short term, then the number will definitely go up as the ability to charge $1 an Mcf versus historically $0.60. Abrazo is significant. So we’re not charging a dollar today, I want to be clear. But if there’s demand for processing and we can get to a dollar-ish fees, then the numbers probably do get into that double-digit range across our facilities. But for now, think of it as a single-digit nice add, no capital, incremental EBITDA, great free cash flow at where we’re focused, but we don’t want to get to a promotional and send a message that, yes, we’re going to have massive adds related to fee increases.
Robert Kwan
Okay. That’s great. Thank you.
Operator
Thank you. Once again, if you — and your next question will be from Michael Simard, Investor. Please go ahead.
Micheal Simard
I just want to clarify, I may have missed this as I came in a few minutes after the call began. But can you just clarify the $0.05 per share net loss for Q3, is that direct result of the inflationary CapEx cost?
Joel MacLeod
Yes. No, no, that the net loss wouldn’t be CapEx related and Doug and team. I believe the main reason is the mark-to-market move within renewables on our feedstock hedges, which you’ll see feedstock for in soybean oil prices essentially hit near a bottom at September 30, where today that, that number is probably moved $20 million to $30 million cat. — if soybean oil prices remain, you’ll see a related net income into December 31. But the main reason for the loss, my understanding and guys jump in, I’m 99% sure but it has nothing to do with the related CapEx. On cash.
Micheal Simard
So would it make sense in the future when you’re doing quarterly releases to just make a note of that on there for investors like myself, just so we get it first around.
Joel MacLeod
Yes. For sure. Fair question. I think maybe we direct your attention to the distributable cash flow number and the EBITDA numbers. So that would kind of have that reflected in it. And then there are some noncash adjustments that we are required to disclose in the order that we do just to allow for reconciliation. But if you want to walk through it, maybe you can give me a shout afterwards, it’s probably new more and we can walk through kind of how it plays out. My contact information just at the end of the press release.
Micheal Simard
Okay. And that’s fine. I mean you’ve just clarified it for me, so I really appreciate that and thank you for that.
Joel MacLeod
Yes. Thank you for your question.
Operator
Yes. Your next question will be from Tom Bauer at Pro Line Group. Please go ahead.
Tom Bauer
Hi. Good morning, guys. I’m a fairly large shareholder and a big believer in your company and like how you deliver on kind of what you guys say. But my question is in regards to your EBITDA multiple that you guys are getting, I mean it’s around 2. When I look at companies like Pembina, Care, Enbridge 5 to 7 range. Just wondering how you plan to try and get the EBITDA multiple up to like more like 5% to 7% because you guys have more growth than most of those other companies, too. Your debt is no worse. I just really don’t understand why the EBITDA multiple stays so low. — main question is just how you plan on getting that up over the next several years? And do you agree that it’s unfairly low.
Joel MacLeod
Hi, Tom. Great question, Joel here. We would agree. Our biggest struggle, I’d say since inception is our cost of capital, just realize our peers are 20x our cost per is probably 20x our size, but I think it’s performance, it’s execution. Some would say the refinery asset definitely brings down our multiple. So we shouldn’t compare ourselves to our larger peers. But I can assure you, Tom, we’re trying as hard as we can to improve our cost of capital. I think our equity raise with the warrant that was attached, definitely wasn’t necessarily helpful to our multiple, but it cleaned up our balance sheet, and now we have a fresh start. So now our focus over the next 12, 24, 36 months is to work to deliver those results where we do expect consolidated EBITDA to grow 25% to 30% here as HDR comes online. So when 9 months here, we do expect to see consolidated EBITDA grow 30-plus percent. And then our goal is, as you said, improve that trading multiple, improve that cost of capital and continue to deliver for our shareholders.
Tom Bauer
Okay. Thank you.
Operator
Thank you. And at this time, we have no further questions. Please proceed.
Joel MacLeod
Thanks, everyone, for your time. If there are any additional questions, please feel free to reach out to any of the team members. Contact info is available at the bottom of the press release. Thanks, everyone. Thank you.
Operator
Thank you. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.
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