Tidewater Midstream and Infrastructure Ltd.

Good afternoon and morning, ladies and gentlemen. Welcome to Tidewater Midstream Q3 Financial Results Conference Call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero 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.

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 McLeod, Tidewater's Chairman and CEO, Brian Newmarsh, 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 present projections. Forward-looking statements we may express or imply today are subject to risk 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 CDAR. And with that, I'll pass it off to Joel McLeod to discuss some highlights from the quarter.

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 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 to 245 million of adjusted EBITDA to 235 to 255 million of consolidated adjusted EBITDA. and do expect the strong performance to continue into and through 2023.

The renewables... I'm sorry, sir, we can no longer hear you. Can you hear us now? Yes, sir, thank you. I'm sorry sir, you're out again. Ladies and gentlemen, please stand by. Please proceed, sir. Thank you. Can you hear me okay?

Yes, sir. We can hear you.

Okay. Sorry about that, everyone. I guess we dropped. We'll take it back and start from the top just because we're not sure where you lost us. So, again, thanks again for joining us today. 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 for 2022 from $230 to $245 million of adjusted EBITDA to $235 to $255 million of consolidated adjusted EBITDA and do expect the strong performance to continue into and through 2023. Mayor Mrakas, renewables business continues to outperform expectations in both adjusted EBITDA and distributable cash flow, but do also want to highlight. Mayor Mrakas, That the consistent with the global economic environment tidewater renewables is experiencing capital costs inflationary pressures as we resolve supply chain disruptions, while adhering to the construction timeline. Tidewater Renewables expects gross capital costs 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 HDRD complex's economic returns as renewable diesel and BCLCFS 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 want to emphasize the HDRD project still expects to have an extremely attractive two-year payback. We walked through the details of these cost increases on the previous Tidewater Renovals Conference call. Back to Tidewater Midstream, industry activity continues to be extremely strong with 172 wells drilled at Pipestone, 97 at Mike SanClements, BRC and 68 at Ram River within a 25 kilometer radius of these facilities in the first nine months of 2022 so again near record high industry activity driving very strong volumes at all of tidewater midstreams facilities. Mike SanClements, 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 three to six 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 two and a half to three time 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 two 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 Mike SanClements, Have a major maintenance turnaround here in the second quarter of 2023. Mike SanClements, print short refining margins average over $895 a barrel during the quarter that's a 5% decrease from our multi year 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, deep bottleneck, 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, 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's 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 Brazzo 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 Brazzo 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 the 100-plus applications as it related to carbon sequestration, Tidewater Midstream was successful and was awarded two evaluation permits for carbon sequestration. one in the Ram River area and one in the Brazzo 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 ACO and related gas prices 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 outperformance 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 six to nine months with the commissioning of the HDRD project. Some quick highlights. On the renewable side, signed a 20-year offtake with Fortis on R&G offtake. Two, an AIMCO credit facility, a five-year senior secured second lien credit facility, and a big thank you to the AIMCO team. And three, we commenced FCC co-processing 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 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.

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 with consistent midstream returns and about $16 million of EBITDA contribution for 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 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 and refining cracks in 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 secondly, notes that we're 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 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 facility to repay the notes was our best path forward. It was not an easy decision to raise equity and dilute existing shareholders, but 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 Joel 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 three-time target. Turning to guidance, as we outlined in this morning's press release, we increased our EBITDA outlook on a consolidated basis to $235 to $255 million. And that's a function of the strong performance within renewables that Joel spoke to and the fact that our... that our midstream business is tracking towards the higher end of our originally guided $180 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 to $40 million to $40 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. This year, we've undergone three major turnarounds in the last six months with our midstream business generating the EBITDA impact that has been offset. The midstream business has had its EBITDA reduction slightly offset by the gas storage assets that have performed very well in the volatile eco-cash markets we've seen over the summer and into the fourth quarter. The weekend and some days negative ACOB cash prices and our Dimmesdale storage asset advantage location in northwest Alberta has allowed the team to capture additional value outside of the hedge summer winter intrinsic 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.

Thank you, sir. Ladies and gentlemen, if you would like to ask a question at this time, simply press star followed by 1 on your touch-tone phone. You will then hear a three-tone 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 a speakerphone, please lift the handset before pressing any keys. Please go ahead and press star 1 now if you have a question. And your first question will be from Rob Hope at Scotiabank. Please go ahead.

Afternoon, everyone. The first questions 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 will characterize larger projects, which I would imagine any of the Pipestone expansion would be during this inflationary time.

Hi Rob, Jules 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 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 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 one 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 two and the related risk is not comparable just given we just built Pipestone one, plan to copy and paste, build a two and would plan to have 10-year take or pay agreements in hand. But good question.

I 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 could have Pipestone, some carbon stuff. How are you thinking about the ability to balance growth at Tidewater midstream as well as LCFS?

It's a really good question, Rob, and something we talked to both boards here over the last few days. As I think we've relayed over the years to try and have two or three large projects going at the same time, especially in an inflationary environment, is something we wouldn't want to do as far as three large projects. So I think two large projects is our maximum, especially in an inflationary environment. In the past with the Pioneer Pipeline and 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 two- to three-year payouts, some with contract profiles, and we have to just allocate capital accordingly, but can assure from both boards' perspective we have to be very selective with our capital, and again, highly unlikely we would try and tackle two large projects at a given time. At the same time, realize the renewables team is now 35, where at the IPO it was two to three, and the midstream team is in the 450 staff members. So we are set up to have, I would say, each entity running one to two 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.

All right. Appreciate the clarity. Thank you.

Thank you. Next question will be from Patrick Kenny at National Bank Financial. Please go ahead.

Thank you. Good morning. Yeah, 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 two here, which I believe was around 240 million. So call it now somewhere in the 265 to 275 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 costs flow through provisions just in order to, hold the economics of the project intact, or maybe there's some other ways that you can mitigate the compression on returns from any increase in capex?

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 capex 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 FIDing 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.

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 the current interest rate environment cause you to lean maybe more towards partnering up with a strategic player in the region? And if so, just curious what operational or value chain synergies exist would be most of interest to you as you look to expand the Pipestone franchise over time?

That'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. In this environment, even it's been a very clear message from our board, we need to continue to have a strong balance sheet. Mike de Rond ... Yeah, 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. Mike de Rond ... I want to be a little careful, because I think even the AIMCO transaction, one example, we're not speaking to AIMCO on Pipestone, but to see AIMCO as a partner in renewables at that cost of capital is very interesting, and then some of our peers We're 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 and in discussions on multiple fronts.

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 COP27 with respect to how Canada might look to cut methane emissions further. 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.

Yeah, Pat, and I think that the Alberta government selecting us for those two carbon sequestration hubs where our understanding is they had a well over 100 applications is significant for us and our customers to be able to sequester CO2, bring down emissions. Even those reservoirs at Brazzo 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 from what we do today, we inject methane into multiple gas storage reservoirs. The infrastructure is there and in place. We're probably set up as well as anyone to help with methane emissions going down hole and into reservoirs that we control.

Perfect. I'll leave it there, guys. Thanks.

Thank you. Next question will be from Robert Cotelli at CIBC Capital Markets.

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 you have all the required in-house expertise to develop those two carbon sequestration hubs? Related to that, most announcements we've seen from the industry involve partnerships. Any thought to partnering a project like this?

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 two and a half to three times. dead deep at a 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 or expertise. I think if you ask around even North America, Western Canada, Given we have sour plants, we have amine, we capture CO2 today, we drilled what I believe are two of the longest total measured DEP AGI wells, which have performed incredibly well. And then we'd be a top five 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 I've proven that given our operations and execution to date. Is it a big focus? I'd want to be careful. No, 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 two, three, four years out and even need another six 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 six to 12 months and hopefully we can provide some real information where now I would just say, Robert, 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.

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, um, you know, the evaluation of the poor space that you've been allocated?

Yeah, 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 counseling, in-house, Even our land department, as far as understanding the mineral rights related to CO2, pore space, I don't think I'm allowed to disclose the dollar amount related to that pore space, but it is very minor and immaterial, which is great to be able to potentially lock up large positions of CO2 pore space and be selected for minimal capital is a material win for us.

Okay. Thanks, guys.

Thank you, Rob.

Thank you. Next question will be from Andrew Kuski at CreditSys. Please go ahead.

Joel, you mentioned earlier just a lot of the activity levels and how they ramped up around some of your facilities. 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, you know, flush of volumes come at you maybe greater than you anticipated before it comes down to more reasonable levels. And then obviously there's a bigger question of, you know, what's the activity levels in the future years. But maybe if you just give us some context to start off with that.

Yeah, 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 it with even some of our reservoirs or our gas storage systems. team, but the Montney, I would say, and Brian would probably have a sense coming from 7Gen, 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 are. Even for us, it's more NGL and liquids yield as well, H2S, obviously percentages coming into our facilities. But we're definitely seeing increased activity. So I think more work to be done, but confident, especially in that Pipestone 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, 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 in an inflationary environment so pipestone i would say more volumes coming in would be confident there when we go down into brazzo there's i feel there's definitely enough and enough data when we look at the manville the nauticu 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 Brazzo. 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, but 450-ish AECO through 26, 27, we do expect volumes to tick up around Brazzo and Ram River.

And maybe just to add to the Pipestone and the Montney commentary specifically, Andrew, I think point well taken around development activity and tight curves that you will have better handle on than we will. I think the other two 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 satiate those incremental pull pipeline flows will be in that zip code that we have assets in, and I think it's just a good place to be in the long run.

Okay, that's very helpful. And then maybe just coming back to some of the incentives, and Joel, you 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, you know, it looks like we will get more incentives. There 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.

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 a year and a half ago or so awarded us, which is public, a significant grant and one of the largest grants, it's great to be near the front of the line for the government's 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.

Okay, that's great. Thank you very much.

Thanks, Andrew. Thank you. As a reminder, ladies and gentlemen, if you would like to ask a question, please press star followed by one on your touchstone phone. And your next question will be from Robert Kwan at RBC Capital Markets.

Please go ahead. Please go ahead, Mr. Kwan, Mr. Kuski.

Mr. Kuski, when? I think it's for Robert. Robert?

No, I'm sorry. We have Andrew Kuski on the line. I apologize. Are you finished?

Yeah, no, I'm good. You can go to Robert.

Okay, thank you. Robert Kwan, RBC.

Great, 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 your fees around to reflect the current environment.

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.

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, you know, holding an EBITDA build multiple for, 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 EBIT valuations, given the interest rate environment that's been rising here?

Yep. 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 beat a six-time 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.

And is that the primary then risk mitigation, just trying to reduce the capital costs 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.

It's a good point. Good point, Robert. The good news is Pipestone 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 three years. So I would say we have a sense of how we want to contract the asset. No material changes to Pipestone Phase 1. 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.

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 is? 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 durations?

Yep, for sure. And as you're aware, all our assets are a little different pipestone. every one mcf is 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 six or so months, we'll have the ability to also likely get volumes on caps. So that incremental volume gas processing at Pipestone is quarked, absolutely, but the more associated liquids we can move is definitely of interest to us. As we move down to our contract term, I would say on liquids, one, two, three-year type deals as far as trucking, where our gas processing, as you're well aware, is 10-year take or pay. As we move down to Brazil, Definitely. We haven't seen this activity in seven-plus years, but I would hate to say producers are ready for 10-year take-or-pay agreements. It's more discussions on two-, three-, four-year, and as our peers group care in particular, as our competitors' plants fill and we fill at Brazeau, there is potential that We can start to look at five-year taker pays, 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 Brazzo, and do feel that will trickle into RAM. So where do we have incremental upside or underutilized capacity? The largest asset would be RAM. Brasso, 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 send them on to TransAlta on 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 yeah, we have five or 10 million a day at Brazil to fill the plant, but increase the margin will be our goal at our facilities. I hope that answers your question.

Yeah, 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-digity but on an annual basis, or is it more?

I think today we would say single digit, Robert, but if you had a view gas prices are going to be $5, $5.50 over the next, even in the short term, then the number will definitely go up as the ability to charge a dollar an MCF. versus historically 60 cents at brazzo is significant so we're not charging a dollar today i want to be clear but if if there's demand for processing and we can get to a dollarish 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 ad nice ad no capital incrementally but a great free cash flow ad where we're focused but don't want to get too promotional and and send a message that yeah we're going to have massive ads related to fee increases.

Okay, that's great. Thank you.

Thank you.

Thank you. Once again, if you do have any questions, please press star followed by one on your touchtone phone. And your next question will be from Michael Smart, investor. Please go ahead.

Yeah, hi. Thanks for taking this call. 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 a direct result of the inflationary CapEx costs?

No, 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 and soybean oil prices essentially hit near a bottom at September 30th, where today that number's probably moved $20 to $30 million to CAD. So if soybean oil prices remain, you'll see a related net income into December 31st. 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. It's on cash. Yeah.

So would it make sense in future when you're doing quarterly releases to just, you know, make a note of that on there for investors like myself just so, you know, we get it first round?

Yeah, 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 non-cash 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 Brian Newhart, and we can walk through kind of how it plays out. My contact information is just at the end of the press release.

Okay, and that's fine. I mean, you've just clarified it for me, so I really appreciate that, and thank you for that.

Yeah, thanks for the question. Thank you.

Thank you. Your next question will be from Tom Bauer at ProLine Group. Please go ahead.

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 two when I look at, you know, companies like Pemina, Kiera, Enbridge, like five to seven range. Just wondering how you plan to try and get the EBITDA multiple up to like more like, you know, five to seven, 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. The 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?

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 20 times, our closest peers probably 20 times 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 HDRD comes online. So in eight, nine 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.

Okay, thank you.

Thank you. And at this time, we have no further questions. Please proceed.

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.

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.