Pembina Pipeline Corp Q3 FY2021 Earnings Call

Good day. And welcome to the Pembina Pipeline Corporation 2021 Third Quarter Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Cameron Goldade, Vice President of Capital Markets. Please go ahead.

Christina. And good morning, everyone. Welcome to Pembina's Conference Call and Webcast to review highlights from the Third Quarter of 2021. On the call with me today, we have Mick Dilger, President & Chief Executive Officer, Scott Burrows, Senior Vice President and Chief Financial Officer, Janet Loduca, Senior Vice President External Affairs, and Chief Legal and Sustainability Officer, Jaret Sprott, Senior Vice President and Chief Operating Officer for Facilities; Harry Andersen, Senior Vice President and Chief Operating Officer for Pipelines; and Stu Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer. I'd like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments, and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see the Company's management discussion and analysis dated November 4, 2021, for the period ended September 30, 2021, which is available online at pembina.com and on both SEDAR and EDGAR. With that, I'll now turn things over to Mick.

Hey. Thanks, Cam. Good morning, everyone. I'm very pleased with the strong results we delivered in the third quarter, reflecting continued robust pricing across all commodities and Pembina's value chain, including crude, condensate, natural gas, and natural gas liquids. The current commodity environment is supportive of our outlook for 2021 and 2022, including an opportunity for Pembina to maintain an above-average contribution from our marketing business next year. As well as strong pricing, which has positive implications for volumes on our existing assets, and the longer-term prospect for business. Including our backlog of currently deferred and potential new growth projects totaling more than $5 billion, with attractive returns. Since the onset of the pandemic, producers have maintained discipline with a focus on productivity improvements, debt reduction, cash generation, and returning capital to shareholders. We remain of the view that the robust commodity pricing environment driven by the post-pandemic economic outlook, rising energy demand with a tight supply curve sets the stage for supply growth into 2022 and beyond. With services across the hydrocarbon value chain, Pembina is poised to benefit from the growing sector activity. Coupled with strong financial performance in the third quarter, Pembina achieved another important strategic milestone with the announcement of our target to reduce the Company's greenhouse gas emissions intensity by 30% by 2030 relative to 2019 baseline emissions. The GHG reduction target will help guide business decisions and improve overall emissions intensity performance, while increasing Pembina's long-term value and ensuring Canadian energy is developed and delivered responsibly. To meet the target, Pembina will focus initially on operational opportunities, greater use of renewable and lower emission energies, and investments in the lower carbon economy. In addition to the GHG target, Pembina expects to make further ESG progress with the announcement of an equity inclusion and diversity target by the end of 2021. As we noted in the release of our materials yesterday, there have been a few other exciting developments recently which support our growing enthusiasm. First, we are encouraged to see a significant announcement from Dow Chemical, highlighting plans to build a new world-scale polypropylene and polyethylene cracker in Fort Saskatchewan in Alberta. We estimate over 100,000 barrels per day of new ethane feedstock supply could be required for this project, which should have positive implications for third-party service providers as new infrastructure will be required for ethane extraction and transportation. Second, we're seeing positive tailwinds on the Alliance Pipeline. A recent open season for short-term capacity was nearly three times oversubscribed, resulting in Alliance being essentially fully contracted through 2022, and the current outlook also supports contracting of capacity beyond 2022. We look forward to providing further updates by the end of the year. Finally, the completion of the line 3 replacement project represents a major milestone for the industry and meaningful advances in Western Canadian oil transportation. In conjunction with the Trans Mountain Pipeline expansion currently under construction, we expect the Western Canadian Sedimentary Basin will soon have up to 750,000 barrels per day of excess takeaway capacity, providing ample opportunity for supply growth, meaningfully filling the gap, with the potential for related benefits to accrue to Pembina also over the long term. I will now pass the call over to Scott to discuss the financial highlights for the third quarter.

Thanks, Mick. Overall, Pembina reported strong quarterly results due to new assets placed into service and the rising commodity price environment. We reported adjusted EBITDA of $850 million for the third quarter, which is 7% higher than the same period last year. The primary driver of the period-over-period increase in adjusted EBITDA was the $75 million higher contribution from our marketing business, which continues to benefit from higher margins on NGL and crude oil sales, and a positive impact of higher marketed NGL volumes. Marketed NGL volumes increased as sales have returned to pre-pandemic levels compared to the third quarter of 2020 when Pembina built up storage positions due to lower commodity prices. As we saw in Q1 and Q2 of this year, the benefit of higher prices and volumes was partially offset by realized losses on commodity-related derivatives as part of our systematic hedging program. Excluding the impact of the realized losses on commodity-related derivatives, third-quarter adjusted EBITDA increased by $127 million over the same period in the prior year, highlighting the potential of the business at current commodity prices. The quarter also benefited from new assets placed into service throughout 2020 and 2021 in our facilities division, including the Prince Rupert terminal, Duvernay III, and Hike Developments. As well, we benefited from higher volumes at Garrison Midstream's Dawson asset and on the Peace Pipeline System. Offsetting these positive factors were the impact of a lower U.S. dollar exchange rate, a lower contribution from Ruby Pipeline due to lower contracted volumes, lower revenue from Kotian Pipeline due to the impact of a timing difference in the recognition of deferred revenue, and higher general and administrative expenses due to the higher long-term incentive expenses as a result of the change in Pembina's share price. Third-quarter earnings of $588 million were 82% higher than the same period in the prior year. In addition to the factors impacting adjusted EBITDA, earnings were positively impacted by the receipt of the $350 million Acquisition Termination Payment, net of the related tax impact, a higher unrealized gain related to certain gas processing fees tied to ACO natural gas prices, and unrealized gains on commodity-related derivatives compared to a loss in the prior period. These positive factors were offset by higher net finance costs, higher transaction costs, and lower share of profit from Ruby Pipeline. For clarity, I want to note that while the tax expense of $76 million related to the acquisition termination payment was accrued in the third quarter, the cash payment of the tax bill is expected to occur in the fourth quarter of 2021. Total volumes of 3.4 million barrels per day for the third quarter were very similar to the same period in the prior year. In pipelines, lower contracted volumes on Ruby Pipeline due to contract expiration, lower interruptible volumes on uncontracted pipelines due to third-party outages, and lower volumes on Vantage Pipeline were partially offset by higher volumes on Peak Pipeline and Alliance Pipeline. In facilities, volumes were lower due to lower volumes at the Saturn complex, due to higher deferred revenue volumes recognized in the same period in the prior year, and lower supply volumes on the East NGL system, as volumes are now being processed at the Empress NGL extraction facility. Volumes were also lower due to take-or-pay relief provided to Redwater complex customers following a third-party outage. Late in the third quarter and into the fourth quarter, we experienced outages on our systems as a result of the fire at a third-party fractionation facility, as well as an unexpected outage on our Northern Pipeline system. Both events were relatively short-lived and Pembina's operations have safely returned to normal. Facility volume decreases were partially offset by higher volumes due to a turnaround in the prior year, higher volumes that vary in midstream Dawson assets, and higher volumes associated with Duvernay III being placed into service in the fourth quarter of 2020. We are also going into the last quarter of the year in a strong financial position with proportionately consolidated LTM net debt to EBITDA of 3.78 times. I'll now turn things back to Mick for some closing comments.

Thanks, Scott. With strong pricing providing a steady tailwind for our business, we remain optimistic about the future as we continue to advance our ESG strategy and progress development of future growth opportunities. Finally, we remain on track to deliver full-year 2021 adjusted EBITDA within our guidance range of $3.3 to $3.4 billion and look forward to providing our outlook for 2022 and the release of our guidance and capital budget in early December. We would once again like to thank all of our stakeholders for their support. With that, the Operator will wrap things up and go to questions. Thank you.

Thank you. We'll take our first question from Rob Hope with Scotiabank.

Good morning, everyone. First question on the Alliance re-contracting. Can you provide a little bit of color here because the renewal contracts expire at the end of October, so you had a big gap there. Did you just really re-contract those last two months? And then, I guess, as a follow-up there, just given the strong demand you've seen, why not look to extend those contracts a little bit further?

Rob, I'm going to pass that over to Harry.

Hey, Rob. Good morning. So to be clear, the contracts, there was a renewal at the end of October for contracts that would expire on November 1st of 2022 for basically the 2022-2023 cash year. When Mick was going through his opening remarks, we spoke about in terms of Alliance essentially being full for 2022, referring to the contract expiries that happened on October 31st of 2020. So as we look at the 2021-2022 gas year, Alliance is essentially full. For the 2022-2023 gas year going forward, we are still in the middle of a renewal process and we expect to have further information by the end of the year.

All right, that's helpful. And then just taking a look at your LPG export terminal, we've been tracking activity at Prince Rupert, seems to be very busy there. When we look at the potential expansion into Q1 of 2022, is this really just wrapping up engineering because you're at a high utilization? And then secondly, what about moving other products that are there rather than just propane?

Jaret.

Good morning, Rob. Yeah. Essentially, we're just wrapping up and getting to Class-3 estimates on the expansion, so doubling the capacity and moving to the medium gas carriers, essentially doubling the cargoes that we can move through there versus the handiest right now. And we expect to make that decision in Q1 of 2022.

Thinking that you have enough propane export, so you don't need to touch Q2?

We're currently focusing on propane, but we will eventually consider Butane. It would be valuable to share insights about the markets we've engaged with and the positive feedback we've received regarding our product quality.

Thank you, Mick. Rob, excuse me. We've been operational since April, and I'm pleased to report that our logistics coordination from the RFS facility has gone well, with 5,400 railcars moved to our PRT site. In this nine-month period, we've processed 3.3 million barrels of propane through the facility. We’re very optimistic about our future growth, with cargoes reaching Japan, South Korea, China, and Mexico. We also completed our commissioning cargoes to Hawaii, and we are proud of the market penetration we've achieved. Our operational teams are producing a low ethane propane, and notably, we have an exceptionally low methanol content, which is uncommon and sets us apart. We're producing what can be described as Pet Chem quality propane at our RFS facility. The feedback on the quality of our products has been excellent, and we believe this positions us well for accessing premium markets going forward.

Thank you. I will jump back in the queue.

So to our next question from Patrick Kenny, with National Bank Financial.

Hey, good morning guys. Maybe just on the Dow opportunity. Could we get your thoughts on when you might need to expand the facilities system, perhaps vantage, and also, does it make sense to strip off some ethane from Alliance at Fort Saskatchewan? Just trying to get a better sense on how you're thinking about feeding Dow that incremental supply over time.

Good morning, Pat. I want to make a quick comment before passing it to Jaret. As you know, we have ethane extraction assets throughout the province, and we're currently reviewing the portfolio. Our customers are looking for more than just one supply source; they want geographically diversified products for clear reasons. They are investing billions and prefer not to rely on a single supply source. Jaret, could you provide some additional insights? Thank you.

You bet, thanks. Good morning, Pat. Like Mick said, we're currently evaluating all of the pipelines that feed our current customers, so between Alliance, vantage, and the peace system, etc. and evaluating the Redwater complex on where we need to expand to provide our customers with that diversification that Mick talked about. They want to ensure that the C2 molecules, their feedstock are coming from a variety of sources. So we're working through that right now. With respect to ethane extraction capabilities, Oksavo does have the contractual rights to straddle the Alliance Pipeline and extract ethane volumes outside of our Shanahan facility at the end of the pipeline. And working with our fantastic partners over at Enbridge, we're currently evaluating that as well to not only satisfy existing demand but also as part of the new expansion that potentially might be coming for the province.

Okay. That's great. Thanks for the color guys. And then just maybe a quick follow-up on Alliance. But more from a longer-term contracting perspective, curious to get your thoughts on how you build out that asset as a conduit to the Gulf Coast. Is this more of a greenfield initiative or look at M&A, more strategic partnerships downstream? Thanks.

Pat, that’s a really insightful question, and I appreciate your input. A significant amount of gas is currently heading to the Gulf Coast, particularly given the favorable export prices. Our discussions with partners indicate that there is approximately 10 billion cubic feet a day of new export capacity being developed in that region. Until we move forward with other initiatives, like our heater LNG projects aimed at Asia, we anticipate that shippers on Alliance will continue to seek access to the coast. This trend has certainly caught our attention and is currently under review. Additionally, there is strong interest in longer-term contracts, which likely relates to Gulf Coast exports. It took us a few years to fully integrate Alliance, but we believe there’s potential to significantly increase gas flow through that line while maintaining our downstream vertical integration.

Great. Thanks Mick, I'll leave it there.

I will take our next question from Shneur Gershuni with UBS.

Hi. Good morning, everyone. Maybe just wanted to start off on the marketing business and how you're thinking about it for 2022. Quality prices have obviously changed dramatically over the last 3 to 6 months, and the frac spreads have opened up as well. Do you expect to continue a hedging program and would it be programmatic in nature? Do you sit there and watch it and see where this market is going? Just trying to get your thoughts as to how you're thinking about the hedging strategy for next year.

The thing about hedging is it's only hedging if you do it with regularity and consistency. So in terms of trending, we said in the notes that we're quite, or very optimistic about what can happen next year in marketing, and that is across the board. We also indicate that all commodities are performing well, and I think you're seeing our customer quarter releases are jaw-dropping and possibly even better in the fourth quarter. And so, when they are making money across all commodities, it certainly helps us to make money, and the differential pricing that we need to have really good outcomes is in place today. So, it's shaping up well. We've taken some risk off the table, and we intend to follow our normal process, because you're never absolutely sure what Mother Nature will do in a warm winter or something unforeseen can upset the differential pricing in a hurry. Many of our downstream activities depend on more than one commodity. As you know, we do intend to keep following our systematic program of hedging.

Great. That makes perfect sense. Maybe if we compare it to the CCUS project that you announced earlier this year that you were exploring. As part of the conversation or announcements at the time you talked about repurposing pipeline and so forth. There's been similar discussions in the U.S. and Texas and so forth, and the conversation seems to always show that the pushbacks have been that CO2 pipes are very different than other pipes, need a thicker steel wall and pressure and so forth. I'm just wondering, are the pipes different that you're planning to repurpose? Is it a scenario where it's more you have it right away when you plan to replace pipe? Just wondering if you can give us a little bit more color or thoughts on how this will come to fruition from a capital perspective.

Yeah, I'll start and then I'll kick it over to Stu. There are a couple of things. Number one, we're looking at a combination. In certain circumstances, we have the right away, but to your point, we don't have the right pipe. Let's say we have an oil pipe and a right away, that's not going to have the pressure capability that we need to move CO2. That's a situation where we could pull a liner or high-pressure pipe within the pipe. That's under review with the regulator, our ability to do that. In places where we do have high-pressure gas pipelines, we've done the work, and we think those pipelines can be retrofitted; they need some work, they need cracker esters put in. But the big difference between Alberta and Texas is it's cold up in Alberta, and the ground temperature remains very cold. This may be one time that it actually acts as a tailwind and helps keep the CO2 in check. Maybe Stu you could elaborate a little bit on where we are in the process and also what our critical path is to take that project off the drawing board and to make it real.

Sure. We have a vision regarding our gathering systems, which we believe offer us a competitive advantage. As a pipeline operator, we possess the necessary expertise in managing high-pressure pipelines and products. We understand the unique nature of CO2 and are collaborating closely with industry experts. As mentioned, we anticipate constructing new pipelines, adding liners to existing ones, and retrofitting certain sections, all aimed at providing a cost-effective CO2 solution. We are committed to collaborating with others to address emission sources. We are actively participating in the Alberta government's carbon sequestration rights process and working in tandem with government officials and our partners to navigate the next steps. We're optimistic about the developments, as we have experts guiding us through this process. The government has indicated that by early 2022, the sequestration permit process should be finalized, enabling decisions on who will have the rights to sequester products in Alberta. We believe we have a robust industry solution for capturing significant emissions in the region, and we are dedicated to advancing this initiative with our customers and government partners.

That makes perfect sense. Really appreciate the technical answer there. Thank you very much, and have a great weekend.

You as well. Thank you.

And we'll go to our next question from Robert Kwan with RBC Capital Markets.

Good morning. Just start with how you're characterizing the nature of the discussions you're having with producers. As you noted, they're holding or they're maintaining a lot of discipline for now, but what's the pace, or how's the pace of inquiries for new capacity and new projects then? Do you see what they're thinking with commodity prices? Just trying to drill into existing capacity to take advantage of high prices quickly? Or is there a growing willingness that you're seeing to make a long-term infrastructure commitment?

Robert, you are likely just as knowledgeable about this as we are. There is significant excitement in the sector, along with plenty of cash, dividends, and share buybacks, even as producers invest heavily in these areas. Recently, I reviewed some data indicating that the average net debt for the Canadian junior intermediate sector and the U.S. sector at the end of 2022 is actually negative. On average, companies in the sector are not going into debt; instead, they are sitting on cash. The only entities that may still have net debt are the senior companies in Canada, but they are meeting their targets. The question moving forward involves pricing and the oil and gas well drilling economics. One positive aspect that emerged from the pandemic is that companies have learned to operate at lower costs. The economics surrounding well activities have never looked better. The timing is uncertain, and while discussions at COP26 continue to present challenges, most producers are no longer reliant on capital markets; they are fully funded internally. They have cash reserves, and my expectation, based on current trends, is that they will begin to drill for gas or oil with quick returns and hedge-able commodities, particularly in drill-to-fill scenarios. The industry as a whole has more flexibility than ever, with the strongest economics observed, and they seem poised to improve further. OPEC is demonstrating considerable discipline, and demand is on the rise as people begin traveling again. From a cash generation standpoint, the outlook is very positive, and we are experiencing significant interest. I believe it’s not a question of if but when this happens. As you pointed out, the level of discipline exhibited now is greater than we have ever witnessed. I am surprised that capital budget volumes have not escalated more quickly; we are in an extraordinary time where the industry is highly profitable and is completely minimizing reliance on capital markets.

That's good color. If I can just turn to marketing and a couple of questions here. You had a statement that you expect marketing to be above average in 2022, and I'm just wondering, I guess, with the changes in your business and the like, and over what time period. What are you seeing as average? The second part, last quarter on the hedging program, you disclosed that pricing on the hedges you added for '22 were in the range or getting a little above the prevailing spot frac spreads in the first half of the year. I'm just wondering if you can give an update on pricing for the hedges you've added subsequent to the quarter.

Scott, you want to keep that one? That's always a delicate question.

Yeah, Rob. We added the 25% hedges throughout Q2, so those would have been at roughly prevailing prices as they relate to Q2. Obviously, since Q2 we've seen a continued increase and rally in the prices. Those 25% we initially put in Q2 would be slightly out of the money today, nothing material I'd say $15 million roughly out of the money, and then the 12% that we added was within the past several weeks here, so relatively close to where the spot pricing is for 2022.

Got it. And then just on the overall above-average commentary on marketing? How are you calculating what's average for you?

I will give you a coarse answer like 2020 was like a P10 year. So on any given 10-year stretch, in the bottom 10%, this year given the strong second half, we are towards a year-end look, we'll be a P-like average year. Next year will be a very good year. So I would say you never know, Robert. Forward-looking information could indicate it could be a P75 year, or better, but we'll wait to see. Remember that it's not just one commodity, but differential pricing that really is key in how we make money, and it's difficult to predict one commodity versus another. But if things were to stay the same moving forward from today's pricing, we have a very good year ahead.

Robert, I would just add that obviously, early December we'll be putting out our capital budget and our 2022 guidance. At that time, I think we'll be able to provide you a little more color to help you with that answer.

Fair enough, and maybe just a follow-on that I know that it's partly marketing, partly maybe facilities, but just any commentary as to what track tightness, NGL kind of mix sloppiness, given the paintings outage and what that means, both near-term and end of '22.

Jaret, do you want to talk about where we sit? How big you think Redwater and the general Edmonton Frac Complex is and maybe that can help Robert out?

Yeah, Robert, good morning. Yeah, the Frac Complex obviously it did get back a couple of little bit with some of the challenges that happened there in late September. But overall, even on a run-rate basis, the Frac Complexes in Fort Saskatchewan are highly utilized right now. Everyone, including ourselves, we're seeing stronger physical gas volumes. Some of our customers have shifted their portfolio a little bit, maybe not as heavily condensate weighted, and a little bit more into that very liquids-rich, but still a lot of gas coming there, which is driving a lot of NGLs down through the value chain. They are all showing up in Fort Saskatchewan, highly utilized. Thankfully, everything is rocking and rolling with the assets and we're seeing a lot of high-processing rates. It's going well and looking very good for when you talked about or there maybe there were questions earlier about where customers are asking for incremental services. There are certain segments of the entire value chain where there are bottlenecks, and that would be one where obviously Pembina is looking at RFS 3 going to the full C2 plus like Redwater, RFS2, etc. Those are the types of things we're looking at to help accommodate the increasing NGLs.

That's great. Thank you.

Go to our next question from Andrew Kuske with Credit Suisse.

Thank you. Good morning. I guess this question is for Mick and it's really when you look at your footprint that you've got and you think about green hydrocarbons attracting premium pricing to what extent do you start allocating capital to effectively provide your customers a turnkey service on a value chain basis for capturing carbon, moving carbon, and then eventually shipping out green hydrocarbons at premium prices? How do you think that fits into the Pembina story that you've got?

Well, I think you're seeing real examples here. The Cedar LNG Project, for example, is using green power and it's going to be one of the greenest LNG in the world. I can't imagine how it would be better than that. We're not participating in the generation of renewable power, but we're acquiring renewable power from long-term renewable power contracts. We've announced the deal with our suppliers. We see the prospects for doing more to help drop our emissions intensity and if possible, our overall emissions, particularly when we don’t keep growing. So that's well underway. We’re looking at a micro-level, on a pilot basis of sequestering all the carbon at Redwater. That's our largest single-point emission source, and we have suitable geology. We can be customers of the Alberta Carbon Grid, an existing pipe there ourselves. We're looking at similar kinds of micro-sequestration opportunities in some of our larger point emission sources in the field where we have the combination of suitable geology and where we're using gas. You turn to Garrison Midstream. Most people don't know this, but that's all hydroelectric power there too. We've got a BCF a day of gross capacity, and that's running on green power also, so we're well down that road. We compare very well on a benchmark basis and we're going to take ground and then we’re trying to do those things to put Pembina on the right footing and in the right direction. However, we're not stopping there; we are actually trying to provide an industry solution, as you described. The most important things for the industry solution is that we and our partner TransCanada are the largest pipeline owners in the province. We’ve got most of our pipe in the province as do TransCanada concerning NGTL, both open access service providers, which we're going to combine. We have combined our efforts to provide a grid, an open access grid, like Pembina does in oil and NGL and TransCanada does on NGTL, and use our surplus pipe and our capabilities, as Stu said. We need the pore spaces and sequestration rights to provide those services to customers. We look forward to doing that. We aspire to do that; obviously, where you put that stuff is really important to that equation, but we'd love to have it in the Pembina story, and we're going to be users of that story ourselves.

That's very helpful context, and I have a follow-up regarding sequestration. Do you think the pricing framework in Canada is sufficient to truly stimulate capital, or is a system similar to 45Q needed in Canada to drive more investment into that industry?

Jaret, do you want to take a crack at that, and I'll add my thoughts after?

One moment while we wait. It looks like we have lost them for just a moment.

I believe the carbon grid and the transportation of sequestration can operate effectively under the current carbon pricing. The capture process is the most capital-heavy aspect, and this is where government support is essential to assist emitters in capturing their emissions. The technology required is well understood and familiar to Pembina, but it is also capital intensive. Therefore, we need government assistance in the form of investment tax credits, quicker tax write-offs, or REIT incentives to initiate this process. Once we have that support, we will be well positioned. The anticipated carbon tax in Canada is significantly higher than what we see in the U.S. and almost anywhere else globally, and it is clear that this will soon be implemented. Carbon capture has the potential to be economically viable.

Okay. That's very helpful. Thank you.

I'll take our next question from Robert Catellier with CIBC Capital Markets.

Hey, good morning, you've actually answered the majority of my questions, so just a couple of small ones here. I noticed there was discussion in MD&A about using rail transportation to position some Propane. I'm wondering what you are seeing the fundamentals there to support that decision, and second part is do you see that as just a tactic based on the current market or is that more of a long-term strategy?

Stu, maybe you and Jaret want to tag team on that.

I'll start, and then Jaret can jump in. Rob, thanks for the question. This isn't unusual for us. We have been using our current asset and have been transporting products by rail. We appreciate the Sarnia Market and its seasonality. We are entering a valuable time, so the economics do support the cost of transporting our product by rail at this moment, and this is not a new practice for us; we have done it regularly. So, Jaret?

No, nothing further.

Do you have any idea when the third-party outage and the related fee relief might come to an end and operations can return to normal?

Jaret, maybe you can take the operating part, and Scott, if you want to chime in on any financial things you want to discuss.

Yeah, Robert, everything is back to 100% operating on our side. And it's been, I don't know, it's been a couple of weeks now that everything has been back to normal. Rob, we don't expect any material impact to our Q4 results.

Okay. Thanks, everyone.

We'll take our next question from Matt Taylor with Tudor Pickering Holt.

Hey, good morning everyone, thanks for taking my questions here. I just want to go back to Alliance and some commentary on how rates on their new contracts compared to the historical rates, just as we saw this spread for ACO to Chicago is quite tight there for allowance for the past quarter or two. So any comments on that and then I know there's been a lot of discussion in the market about Alliance and how the 3x oversubscribed open season is changing your outlook for that pipe longer-term.

I'm just going to make one comment and then turn it to Harry. Our longer-term outlook on that site has never changed; even when we had a $0.60 differential, it’s going to move around, but our view, and I know our partner Enbridge, has always been that this is the best pipeline from Canada going into the U.S. and our outlook has always remained positive. Harry.

Thanks, Mick. And good morning, Matt. I'll just follow behind Mick on the longer-term outlook. The structural advantages that Alliance has enjoyed over 20 years, we firmly stand behind them. Stu and Mick have talked about seeing some additional structural events come into play for Alliance around the LNG exports off the East Coast and also off the U.S. Gulf Coast. Combined with what we're seeing as still a movement towards switching from coal-fired to gas-fired, and nuclear to gas-fired as well. So, long-term, the structural advantages that Alliance has enjoyed are still there and have actually become a bit more robust. From a pricing perspective, I will comment in terms of the 2021-2022 gas year. The volumes that we picked up there were on average about 130% in excess of the current toll. For the 2022-2023 and longer gas year and beyond, we're currently in a process working with the shippers out there, so there's not much I can say, but we're expecting to have an update before the end of the year.

That's great. Thanks for that, Harry and Mick. And then I have one on Cochin as well, probably first need for Scott. Is that deferred revenue issue material and is that just a one-off? And then, previously you guys have been talking about potentially adding more capacity. And Mick, is outlined bullishness on volumes here; are conversations heating up that capacity could be imminent as well? In your capacity, that is.

Matt, no, the overall result was not material and a lot of it just relates to the timing of makeup rights and other things on our system, so it was less than $10 million to the quarter. With that, maybe I'll pass it over to Harry.

In terms of increasing the capacity of Kotian, discussions are ongoing and obviously the condensate market in Alberta is very robust and I think we feel positively about the direction Kotian is going, both from a volume and price perspective.

Thank you for that. Lastly for Mick, could you provide more details about the comments in the media regarding the advantages of integrating some of the CCUS projects and the feedback we've heard related to a premium for that service? Some ongoing projects might have a more refined approach. Would you be able to address some of these key counterarguments and share your vision for a broader system in Alberta?

It's puzzling how someone could claim that a premium is necessary when the pipes we intend to use are fully depreciated. We're only seeking a return on the additional investment, which we've communicated to the market as being about $0.50 on the dollar compared to new pipes, while others are required to construct entirely new infrastructure. I can't quite understand the basis for that statement. However, if someone can achieve it at a lower cost independently, they will certainly pursue that option. We'll just have to wait and see.

Great Thanks for that.

So to our next question from Linda Ezergailis with TD Securities.

Thank you. I look forward to getting more information in December. In the meantime, could you help us understand where you might find some operating leverage in your system in 2022, in terms of volume? Any updates on key sensitivities related to commodity prices, foreign exchange, or other factors would be appreciated. Additionally, how should we view inflation concerning revenue and costs, especially regarding any protections you have in place? Could inflation potentially become a positive factor for you next year?

I'll address a few key points. First, regarding inflation, it's important to prioritize our employees since the current scarcity of goods and services is closely related to workforce challenges. We're dedicated to supporting our team. Additionally, ensuring that we have necessary spare parts on hand is crucial, as obtaining items can be difficult at this time. We've been proactive in maintaining critical spare parts in our inventory. From a financial perspective, about 75% of our operating costs are influenced by pass-through expenses, which we understand impact our customers. We're committed to enhancing efficiency and have invested tens of millions of dollars in improvements since 2020, which continues to be a priority for us and our board. Furthermore, inflation tends to align with commodity prices; therefore, we believe the residual inflation we experience is somewhat manageable. We expect our marketing efforts will generate revenue that exceeds the effects of inflation. On the financing side, while inflation can influence interest rates, we are well-protected against long-term rate increases. Scott may want to add more to this discussion. Lastly, regarding our leverage, we have significant capacity in our midstream facilities and low-cost expansion opportunities in Kotian and Alliance. Our conventional pipeline business shows potential as we operate at 75% to 80% capacity, providing a solid opportunity for increased output. However, as Jaret mentioned, our frac and gas processing operations are nearing full capacity.

Linda, I would just also add that approximately 90% to 91% of our debt is on fixed rate. We do have somewhere in the neighborhood of $900 million that's exposed to floating rates that we're looking at what to do with that here in the short-term. We also have short-term rate exposure at Garrison Midstream as well, but we've hedged 50% of that away. As it relates to sensitivities, please bear with us one more month; we'll obviously have to lay out all of our sensitivities in conjunction with our 2022 budgets. So that will form part of that press release.

Thank you. And on a separate note, some headlines recently that your Oregon LNG Pipeline approval was to get a new FERC review, recognizing what's not a high priority initiative now. Just wondering what the thinking is there, and might others in the industry find more value in that initiative or what are the moving parts?

This is Janet and thanks for the question. I think as we've announced previously, we paused the Jordan Cove development at this point. And while we haven't made any decisions, we're continuing to work with FERC, including on the appeal. I think we'll have to continue to evaluate. We do see that there is value to this asset in some way, shape, or form, so I think more to come on that.

Thank you, and maybe as a broader question with respect to maximizing value, how might acquisitions and divestitures be leveraged where outright trading of assets might optimize bigger lower-cost solutions for the industry versus partnering like resuming with the Alberta Carbon Grid?

That's a great question, Linda. Ultimately, assets end up with the owners who can best utilize them. Swapping assets can be an excellent solution if they hold greater value for the other party. We are exploring similar options and considering the ability to cycle capital more than we have in the past. As we approach 2022, we will discuss this further in December. We are in a strong position, generating substantial cash with a low payout ratio, minimal debt, and a lot of upside potential. We feel very optimistic about the opportunities that lie ahead for next year.

Thanks for answering my questions.

Thank you, Linda.

And we'll take our next question from Ben Pham with BMO.

All right, thanks. Good morning. I wanted to ask a question on M&A. I'm curious about the activity you're seeing and your appetite for willing sellers out there given improvements in asset values in other geographies that we look to now they haven't slipped before. I'd love your high-level comments on M&A.

We prefer to grow with connected assets or those that are linked through contracts. For instance, we aren't physically connected to Prince Rupert, yet our long-term rail agreements imply a connection and vertical integration. Focusing on connected assets is beneficial as it allows us to provide services throughout the value chain, ensuring that at least part of it has sufficient capacity. If we were to secure a significant new NGL contract, such as one from Dow for C2+, we could establish a field facility that requires additional capital, but because our pipeline can accommodate it without further investment, much of the revenue would go directly to our profits. While we might need to build a new terminal, existing storage and rail capabilities for C3+ would suffice, as we are already connected to other facilities, eliminating the need for new capital in those areas. This highlights how some ventures require investment while others do not, with the latter contributing significantly to profitability. We can even share these gains with customers for improved netbacks, which is why we prioritize connectivity. In Europe, for example, it’s less clear how the combination of assets would create significant value, so we tend to avoid those situations. We've learned the importance of building from a foundation of strength, with solid assets and customer relationships. Our major assets in Chicago provide us with valuable experience in that market, offering promising opportunities for growth.

And then my second last question is on Ruby. The tracking of your initial expectations is there a tracking line?

I don't think I understand the question, but I'm going to turn it over to Harry. Maybe he understood, and he can answer it.

Yeah, generally yes, we can't give you the specifics.

There has been, I think, obviously, the producer contracts rolled off at the end of July. Q3 was a pretty decent run rate for Ruby going forward. There have been some short-term deals there that have backfilled some of the volumes on a short-term basis, but not meaningful contributors to revenue just given the current spread. I would say that where we're at, balance of Q3 and into Q4 is going to be the run rate for Ruby.

Thank you all for your questions. We need to move on to the Employee Town Hall, and I appreciate the interest. We usually don’t take the full hour, so I thank you for that. We are currently experiencing many favorable conditions. Our existing assets are performing well, and our customers are in great health, better than I have ever seen. The potential for them is enormous, and I hope this translates into increased volumes soon, which will help drive our activities forward. I look forward to sharing our updated insights for 2021 in December and giving a deeper look into 2022 at that time. Thank you again, and have a wonderful weekend. Goodbye.

This concludes today's call. Thank you for your participation. You may now disconnect.