Pembina Pipeline Corp

TSX:PPL

Earnings Call Transcript 2021-Q3

[Operator]

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.

[Cameron Goldade, Vice President of Capital Markets]

Thank you, 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 and 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.

[Michael H. Dilger, President, CEO & Director]

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 in 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 in 2022, including an opportunity for Pembina to maintain an above-average contribution from our marketing business next year. As well, strong pricing is 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 -- polyethylene cracker in Fort Saskatchewan, 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 are seeing positive tailwinds on the Alliance pipeline. A recent open season for short-term capacity was nearly 3x 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 Line 3 Replacement Project represents a major milestone for the industry and meaningful advances in Western Canadian oil egress. 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 to fill the gap, with the potential for related benefits to accrue to Pembina also over the long term. I'll now pass the call over to Scott to discuss the financial highlights for the third quarter.

[J. Scott Burrows, Senior VP & CFO]

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, 7% higher than the same period last year. The primary driver of the period-over-period increase in adjusted EBITDA was a $75 million higher contribution from our marketing business which continues to benefit from higher margins on NGL and crude oil sales and the 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 $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, Empress Infrastructure, Duvernay III and Hythe Developments. As well, we benefited from higher volumes at Veresen Midstream's Dawson assets and on the Peace Pipeline system. Offsetting these positive factors was the impact of a lower U.S. dollar exchange rate, a lower contribution from Ruby Pipeline due to lower contracted volumes, lower revenue from Cochin Pipeline due to the impact of a timing difference in the recognition of deferred revenue and higher general and administrative expense 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 period 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 AECO natural gas prices and unrealized gain on commodity-related derivatives compared to a loss in the prior period. These positive factors were offset by higher net finance costs, higher transformation and 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 expirations, lower interruptible volumes on AEGS due to third-party outages and lower volumes on Vantage Pipeline were partially offset by higher volumes on Peace 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 a 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 at Younger due to a turnaround in the prior year, higher volumes at Veresen Midstream's 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 proportionally consolidated LTM net debt-to-EBITDA of 3.78x. I'll now turn things back to Mick for some closing comments.

[Michael H. Dilger, President, CEO & Director]

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 billion to $3.4 billion and look forward to providing our outlook for the 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, operator, we'll wrap things up and go to questions. Thank you.

[Operator]

[Operator Instructions] We'll take our first question from Rob Hope with Scotiabank.

[Robert Hope, Analyst]

First question is on the Alliance recontracting. Can you add a little bit of color here because the Seven Gen contract expires at the end of October. So you had a big gap there. So did you just really recontract those last 2 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?

[Michael H. Dilger, President, CEO & Director]

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

[Harold K. Andersen, Senior VP & Chief Operating Officer of Pipelines]

So to be clear, the contracts, there was a renewal at the end of October, that for contracts that would expire in November 1 of 2022, so for basically the 2022-2023 gas year. So when Mick was going through his opening, what we spoke about in terms of Alliance essentially being full for 2022 where the contract expiries that happened October 31, 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.

[Robert Hope, Analyst]

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

[Michael H. Dilger, President, CEO & Director]

Jaret?

[Jaret A. Sprott, Senior VP & COO of Facilities]

Yes, 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, so essentially doubling the cargoes that we can move through there versus the [indiscernible] right now. And we expect to make that decision in Q1 of 2022.

[Robert Hope, Analyst]

And then thinking that you have enough propane exports, so you don't need to touch butane?

[Michael H. Dilger, President, CEO & Director]

We're looking -- we'll eventually look at butane. Right now, the focus is on propane. Stu, maybe I think it'd be interesting to listeners, just to talk about the markets we've hit and the positive feedback we've gotten on our product quality.

[Stuart V. Taylor]

Yes. Thanks, Mick. So we've had -- we've been up and running since April. Really happy to report the logistics coordination from our RFS facility, the rail loading and we've moved 5,400 railcars to our PRT site. We've moved 3.3 million barrels of propane through the facility in 9-month period here, essentially. And we're really excited about the future and the growth. We've got cargoes into Japan, South Korea, China and Mexico. And we did our commissioning cargoes into Hawaii. And so we're really happy with where the destinations have -- we've been able to penetrate or move that into the market. One of the things that we're excited about is, again, our operating teams were producing a low ethane propane. And in particular, we have a very exceptionally low methanol content, which is unique for us. We're producing, what I'd like to refer to as, petchem quality propane at our RFS facility that allows us -- we're getting great feedback on the quality of the product that we're loading, and we believe that opens up premium markets on a go-forward basis.

[Operator]

We'll go to our next question from Patrick Kenny with National Bank Financial.

[Patrick Kenny, Managing Director]

Maybe just on the Dow opportunity. Could we get your thoughts on when you might need to expand the AEGS system, perhaps Vantage. And also does it make sense to strip off some ethane from Alliance at Fort Saskatchewan. Just want to get a better sense on how you're thinking about feeding Dow that incremental supply over time.

[Michael H. Dilger, President, CEO & Director]

I'm going to just make a quick comment, then turn it over to Jaret. We -- as you know, we have assets -- ethane extraction assets all over the province. So we're just sorting through the portfolio. And frankly, the diversification that our customers are asking for, they're not asking for just 1 source. They want diversified -- geographically diversified product for obvious reasons. They're putting billions into the ground, and they don't want to be beholden to 1 supply source. So Jaret, maybe you can add some color.

[Jaret A. Sprott, Senior VP & COO of Facilities]

Yes, you bet. Like Mick said, so we're just currently evaluating all of the pipelines that feed our current customers, Pat, so between AEGS and Vantage and the Peace system, et cetera, and evaluating the Redwater Complex on where do we need to where do 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 just kind of working through that right now. With respect to Aux Sable, Aux Sable does have the contractual rights to straddle the Alliance Pipeline and extract ethane volumes outside of our Channahon 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.

[Patrick Kenny, Managing Director]

Okay. That's great. 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 do you have to look at M&A, more strategic partnerships downstream?

[Michael H. Dilger, President, CEO & Director]

Yes, Pat, it's a very insightful question, it's like you're giving us tips on what to do next, but thanks for that. Yes, a bunch of this gas is making its way to the Gulf Coast and with $20-plus in Mcf product, you can imagine why. And Stu told our Board yesterday that there's a better part of 10 Bs a day of new export capacity being developed on the Gulf Coast. And until more things happen like our Cedar LNG Project, albeit that goes to Asia, we think there's going to be a continued desire for shippers on Alliance to get to the coast. And certainly, that's caught our attention. So that is under review. And I think some of the -- Harry mainly touched on the shorter-term contracting, but there's also a very robust activity for longer-term contracts interest underway, and I'm quite certain some of that has to do with Gulf Coast exports. So it took us a few years to digest Alliance. I think there is possibility with Alliance to really put a lot of gas into that line. And to look downstream as we have for where does the ethane go? Where does the propane go? Where does the methane go and keep our vertical integration going downstream? And I know Stu's team is looking at that.

[Operator]

I'll take our next question from Shneur Gershuni with UBS.

[Shneur Z. Gershuni]

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

[Michael H. Dilger, President, CEO & Director]

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 on what can happen next year in marketing. And that is across the board. We also said in the piece that all commodities are doing well. And I think you're seeing our customer quarter releases are, I mean, jaw dropping and possibly even better in the fourth quarter. And so when they're 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 good. And I think 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 offset the differential pricing in a hurry because many of our ARPS depend on more than 1 commodity, as you know. And so we have to be cautious. So we do intend to keep following our systematic program of hedging.

[Shneur Z. Gershuni]

Great. No, that makes perfect sense. Maybe if we can pivot 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 -- or the pushbacks rather have been that CO2 pipes are very different than other pipes, thicker steel wall and pressure and so forth. Just wondering, are the pipes different that you're planning to repurpose? Is it a scenario where it's more you have the right-of-way and you plan to replace pipe? Just kind of wondering if you can give us a little bit more color or thoughts on how this will come to about from a capital perspective.

[Michael H. Dilger, President, CEO & Director]

Yes, I'll start out and then I'll kick it over to Stu. There's a couple of things. Number one, we're looking at a combination. So in certain circumstances, we have a right-of-way. But to your point, we don't have the right pipe. Let's say, we have an oil pipe in a right-of-way, that's not going to have the pressure capability that we need to move CO2. And so that's a situation where we could pull a liner, a high-pressure pipe within the pipe. That's under review with the regulator, our ability to do that. In places we do have high-pressured gas pipeline, 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 damn cold up in Alberta, and it's cold and the ground temperature remains very cold. And so that is a fundamental tailwind we have and most of the time we're complaining about it. This might be the one time that it's actually a positive and it keeps that CO2 in check. Maybe Stu, you could elaborate a little bit where we are on the process there and also what our critical path is to take that project off the drawing board and to make it real.

[Stuart V. Taylor]

Sure. So again, I think we have a vision and as described, we believe there is an advantage to our gathering systems that we have. And you've highlighted is it right-of-ways or is it pipelines. We also believe as a pipeline operator, that we have expertise. We move high-pressure pipelines and products. We do appreciate the difference in CO2 is, and we're working exceptionally closely with industry experts. As Mick described, I think you're going to see as we come forward, that we will be building new -- some new pipe. We will be putting liners in other pipes and retrofitting some of our pipes, all an attempt to be -- to provide a CO2 solution at the lowest possible cost. We recognize we will be working with others collaborating on how to do that, where the emissions are going to come from. And so we're working hard. We are part of the government of Alberta's process on the carbon sequestration rights that the government is working through.We're working with the government, with our partners, extensively with our partner on how to proceed. And we're excited about the progress. We've got experts helping us along the way. And so as the government has described, we're hoping in early 2022 that the sequestration permit process will be through and the government will be making some decisions on who have the rights to sequester products in Alberta. We believe we have a strong solution, an industry solution to capture a lot of the emissions in Alberta and working with customers and the government to progress that path and that process.

[Operator]

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

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

Just start with how you're characterizing the nature of the discussions you're having with producers. As you noted, they're holding -- they're maintaining a lot of discipline for now, but just what's the pace or how has the pace of inquiries from your capacity and new projects been? And do you see and it felt their 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?

[Michael H. Dilger, President, CEO & Director]

Robert, you would know that answer as well or almost as well as we do. I mean there's so much excitement in the sector and so much cash and dividends and share buybacks. And even when the producers are allocating a ton of money to both of those activities, I looked at -- through some tables the other day and the average net debt at the end of 2022 for the Canadian junior intermediate sector and the U.S. sector is actually negative. On average, people across the sector are not going to have debt. They're going to have cash in the bank. The only people that are going to have remaining net debt are the seniors in Canada and they're all meeting their targets. I read Synovus' release. And so the question remains at these prices and with the economics of oil and gas well drilling, I mean, the silver lining through the horrible pandemic is people learn how to do stuff at low cost. And so the economics of wells, of activities have never been better.The question to me then is when? And there's lots of talk still out of COP26 and everything that is a headwind. But most producers don't have any reliance whatsoever on capital markets anymore. I mean they're completely internally funded. They don't need bank debt. They got cash in the bank. And my prediction is, this is one man's prediction, when they can drill gas, drill oil with very fast payouts with hedgeable commodities that they're going to start to take ground, particularly drill-to-fill situation. So if a producer has capacity in their gas plant or we have capacity in our plant or they're paying for service that they're not fully utilizing. As we said in the call, we've got Line 3. So there's no mystery about egress anymore that was all a headwind. So I think that the things that can be done relatively -- with relatively fast payouts will drive production up. What remains to be seen, are there going to be new SAGD trains and things like that happening? Or is the industry just going to slowly scale up to its egress capacity?Even if it did that with Shell coming on in some time and Line 3 there with surplus capacity, and Trans Mountain coming, the industry has more running room with the best economics I've ever seen. And they look like they're going to get better, not worse. I think OPEC is showing a lot of discipline. And even there, we know that there's hiccups from some of the smaller countries not being able to meet their quotas. And demand is returning. People are getting back on airplanes. So I think things are looking very, very good from a cash generation perspective. And we have lots of inbound interest. And I think it's not if, it's when. But to your point and the reason for your question is this is more disciplined than we've ever seen. Like I'm a bit surprised the volumes and capital budgets haven't ramped up more significantly. It's just an incredible time in the industry is making a ton of money and they're shedding, I think, reliance on capital markets entirely, and there may be good reasons for that. I know that's a long answer.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

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 even a little about 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.

[Michael H. Dilger, President, CEO & Director]

Scott, do you want to -- that's always a delicate question. Maybe, Scott, you could take that one.

[J. Scott Burrows, Senior VP & CFO]

Yes, Rob. We added the 25% hedges kind of throughout Q2. So those would have been at roughly prevailing prices as it relates to Q2. Obviously, since Q2, we've seen a continued increase in rally in the prices. So those 25% that we initially put in, in Q2 would be slightly out of the money today, nothing material. I'd say, 15 -- call it, $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.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

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

[Michael H. Dilger, President, CEO & Director]

I give you a course answer like 2020 was like a [ P 10 ] year. So in any given 10-year stretch in the bottom 10%. This year, given the strong second half and the way the -- towards year-end look will be a P like an average year. And next year will be a very good year. So I would say you never know, Robert, so like forward-looking information, but it could be a [ P 75 year ] or better but we'll wait to see. Remember, it's not just 1 commodity, it's differential pricing that really is key in how we make money, and it's really difficult to predict 1 commodity versus another, but if things were not to change from today's pricing, we have a very good year.

[J. Scott Burrows, Senior VP & CFO]

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

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

Fair enough. And maybe just to follow on that. I know that it's partly Marketing partly maybe Facilities, but just any commentary as to what frac tightness NGL kind of mix sloppiness given the planned outage and what that means both near term and into 2022?

[Michael H. Dilger, President, CEO & Director]

Jaret, you want to talk about where we sit, how busy you think Redwater, the general Edmonton frac complex is and maybe that can help Robert out.

[Jaret A. Sprott, Senior VP & COO of Facilities]

Yes, Robert. Yes, the frac complex, obviously, it did get backed up a little bit with some of the challenges that happened there in the late September. But yes, overall, even on a run rate basis, the frac complex is in Fort Saskatchewan, they're highly utilized right now. Everyone, including ourselves, we're seeing stronger physical gas volumes. Some of our customers have shifted their portfolios a little bit to 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, and they're all showing up in Fort Saskatchewan. So highly utilized. Thankfully, everything is rocking and rolling with the assets, and we're seeing a lot of high processing rates. So it's going well, and it's looking really good for -- when you talked about -- or maybe there's a question earlier about where the customer is 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 looking at RFS III going to the [indiscernible] out there and going to a full C2+ like Redwater, RFS II, et cetera. Those are the types of things we're looking at right now to help accommodate the customers' increasing NGLs.

[Operator]

We'll go to our next question from Andrew Kuske with Credit Suisse.

[Andrew M. Kuske]

I guess the 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 store that you've got?

[Michael H. Dilger, President, CEO & Director]

Well, I think you're seeing real examples here. I mean the Cedar LNG project, for example, is using green power. And so it'll probably be the greenest LNG in the world, I can't imagine how it would be better than that. So that's obviously going to be a coveted product. We are not participating in the generation of renewable power, but we're acquiring renewable power from long-term renewable power. We've announced a deal. We see the prospects for doing more of that to help drop our emissions intensity and if possible, our overall emissions, particularly if we don't keep growing. So that's well underway. We are looking at on a micro on a pilot basis, sequestering all the carbon at Redwater. That's our largest single point emission source, and we have suitable geology, and we can be customers of the Alberta carbon grid and existing pipe there ourselves. We're looking at similar kind of micro sequestration opportunities in some of our larger point emission sources in the field where we have the combination of the right geology and where we're using gas. You turn to Veresen Midstream, most people don't know this, but that's all hydroelectric power there, too. So we've got a Bcf a day of[Audio Gap]gross capacity there that's all run on green power. So we're well down that road. And so we compare pretty well on a benchmark basis, and we're going to take -- keep taking ground. And then we're trying to -- those are the things that we're doing to put Pembina on the right footing and in the right direction.And -- but we're not stopping there. We're actually trying to provide an industry solution as you described. One of the most important things, though, for the industry solution is that we and our partner, TransCanada, is the largest pipeline owners in province. We've got most of our pipes in the province has does TransCanada in terms of NGTL, both open access service providers. So we're going to combine, and 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 as Stu said, our capability but we need the poor space, the sequestration rights to be able to offer those services to customers. So we look forward to doing that. We aspire to do that. But, obviously, where you put that stuff is really important to that equation, but we'd love to have that in the Pembina Store, and we're going to be users of that store ourselves.

[Andrew M. Kuske]

That's very helpful color and context. And then I guess maybe just a follow-on and it relates to on the sequestration side of it. Do you think the pricing regime in Canada is enough and the pricing regime on carbon is enough to really stimulate capital? Or do you need like a 45Q equivalent in Canada to really drive more capital into that industry?

[Michael H. Dilger, President, CEO & Director]

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

[Operator]

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

[Michael H. Dilger, President, CEO & Director]

Okay. I'll take that. I think the carbon grid and the sequestration, the transportation can work at today's carbon pricing. I think the capture is the most capital-intensive part, and that's where -- the level the government need to kick in is really to help producers, the emitters capture their emitters. It's all a well-understood technology Pembina knows and has experience with but it's capital intensive. And so we do need assistance from the government with investment tax credits or fast write-off tax pools or just outright incentives to get that started and then we will be good. I think the projected carbon tax in Canada is way, way beyond what we see in the U.S. and in, I think, almost anywhere in the world. And so clearly, were that to come to pass, carbon capture could be economic.

[Operator]

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

[Robert Catellier]

You've actually answered the majority of my questions. So just a couple of small ones here. I noticed there was a discussion in the MD&A about using rail transportation to position some propane at Corunna. I'm wondering what you see in the fundamentals there to support that decision. And the 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?

[Michael H. Dilger, President, CEO & Director]

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

[Stuart V. Taylor]

Yes, I'll start and then Jaret can jump in. So Rob, thanks for the question. This is not uncommon for us. We actually have been using our current asset. We've railed products in. We do like. We like the Sarnia market. We like the seasonality of the Sarnia market. We're coming into a valuable time. So yes, the economics do justify the cost to rail our product at this point in time. And it's nothing new for us. We've done it on a regular basis. So Jaret?

[Jaret A. Sprott, Senior VP & COO of Facilities]

No nothing further.

[Robert Catellier]

Okay. And then just with the third-party outage and the take-or-pay fee relief related to that? Do you have any line of sight as to when that might mitigate and get back to normal operations there?

[Michael H. Dilger, President, CEO & Director]

Jaret, maybe you can take the operating part. And Scott, if you want to chime in on any financial things you want to talk about there?

[Jaret A. Sprott, Senior VP & COO of Facilities]

Yes, Robert, everything is back to 100% operating on our side. And it's been, I don't know, I would probably have to get, but it's been a couple of weeks now that everything has been back to normal.

[J. Scott Burrows, Senior VP & CFO]

Rob, we don't expect any material impact to our Q4 results.

[Operator]

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

[Matthew Taylor, Director of Midstream Research]

I just want to go back to Alliance. If you could provide some commentary on how rates are on new contracts compared to the historical rates just as we saw the spread for AECO to Chicago was quite tight there for a while and for the past quarter or 2. So any comments on that? And then I know there's been a lot of bearishness in the market about Alliance and how the 3x oversubscribed open season is changing your outlook for that pipe longer term.

[Michael H. Dilger, President, CEO & Director]

I'm just going to make one comment and then turn it to Harry. Our longer-term outlook on that pipe has never changed even when we had a $0.60 differential, it's going to move around. But our -- and I know our partner Enbridge, our view has always been that the best pipe from Canada going into the United States and our outlook has always been very, very positive about that pipe. Harry?

[Harold K. Andersen, Senior VP & Chief Operating Officer of Pipelines]

Yes. Thanks, Mick. I'll just follow in behind Mick on the longer-term outlook. Mix rate, the structural advantages that Alliance has enjoyed over its 20 years. We firmly stand behind. And as Stu and Mick have talked about, we're seeing some additional structural advantages come into play for Alliance around the LNG exports off the East Coast and also out in the U.S. Gulf Coast, combined with what we're seeing is 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 enjoyed are still there, and we're actually seeing to get being a bit more robust. From a pricing perspective, I'll talk about in terms of the 2021-2022 gas year. So the volumes that we fund up there were, on average, about 130% in excess of the current toll for the 2022-2023 and longer gas year. And beyond that, we're currently in a process with working with the shippers. So there's not much I can say, but we're expecting to have an update before the end of the year.

[Matthew Taylor, Director of Midstream Research]

That's great. And then I have one on Cochin as well, probably firstly for Scott. Is that deferred revenue issue material? And is that just a one-off? And then previously, you guys have been talking about adding -- potentially adding more capacity and Mick as you've aligned bullishness on volumes, conversations heating out there that capacity could be imminent as well, new capacity that is?

[J. Scott Burrows, Senior VP & CFO]

I'll take the first part of that question and then turn it back to Harry. Matt. No, the overall result was not material and a lot of it just relates to the timing 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.

[Harold K. Andersen, Senior VP & Chief Operating Officer of Pipelines]

Yes. In terms of increasing the capacity of Cochin, discussions are ongoing. Obviously, the condensate market in Alberta is very robust and I think we feel positively about the direction Alliance is going both -- or sorry, and Cochin is going, both from a volume and a price perspective.

[Matthew Taylor, Director of Midstream Research]

Great. And then last one for Mick. Can you elaborate a bit more on -- there are some comments out there in the press about you've seen the benefit of combining some of the CCS projects out there and some of the pushback we've been hearing is [indiscernible] a third-party premium for that service and/or some of those other continuing projects might be a bit more refined in scope. So would you mind just touching on some of those key rebuttals and what your vision is for a broader system in Alberta?

[Michael H. Dilger, President, CEO & Director]

Yes. I mean it's confusing how someone could say they would need to pay a premium given that our pipes are -- that we're proposing to utilize our fully depreciated and we're only trying to make a return on incremental investment, which we've said to the market, we expect to be about $0.50 on the dollar compared to new or as other proponents need to build brand-new pipes. So I can't really ascertain the root of that comment. But listen, if someone can do it less costly on their own, clearly, they're going to do it. And I guess we'll wait and see.

[Operator]

We'll go to our next question from Linda Ezergailis with TD Securities.

[Linda Ezergailis, Research Analyst]

Recognizing we'll get more information in December, and I look forward to that. I'm wondering if you could help us understand in the meantime a little bit about where there might be some operating leverage that you could benefit from in your system in 2022 volumetrically? Any updates you could provide on key sensitivities, whether it be commodity prices, FX or anything else would be helpful. And then from a model perspective as well, how might we think of inflation puts versus peak on the revenue side versus the cost side in terms of any sort of commercial protections in place? And then whether that inflation might actually prove to be a net tailwind for you next year?

[Michael H. Dilger, President, CEO & Director]

Yes, I'll take a couple of those. So starting with inflation. When we think about scarcity of goods and services, the #1 thing is we've got to take good care of our employees because a lot of the scarcity we're reading about has to do with employees. And so we're very focused on that. And then the next thing in regards to the cost is making sure you have all the spare parts you need as we're all learning in our personal lives, it's hard to get stuff right now. So we've looked at having critical spares and spare parts and inventory across our systems. In terms of the monetary part of inflation, number one, I think about 3/4 of our operating costs are pass through. We're obviously very cognizant that those costs matter to our customers. And so we're doing everything we can to drive efficiency, and we've literally put tens of millions of dollars of efficiencies into our business since 2020, and that remains an ongoing focus of ourselves and our Board. Lastly, we observed that often inflation does correlate relatively well to commodity prices. And so to the extent we're left with remaining residual inflation, we think there's a good hedge, at least that's what's happening now, I would say, our ability to make money from our marketing business has been a far outstrip inflation that we see on the financing side. Obviously, inflation can lead to interest rates. And we're really well hedged in terms of long-term interest rates. Maybe Scott wants to add something to that.And then lastly, or second last, I'll open it up probably to Scott next. But where do we have leverage? We have leverage in Veresen Midstream. We have quite a bit of capacity there. We have leverage, obviously, on Cochin. We have some very low-cost expansions there. We have a low-cost expansion on Alliance that we've talked about in the past. You never know. We have significant leverage across our Conventional Pipelines business. We are still operating in that business around 3/4 to 80% full. And so tremendous torque on adding barrels there. So the places were more full as Jaret said is on our frac business and some of our other gas processing businesses.So Linda, we can run quite a while within our footprint. But -- and that sounds great, and it is great, but it also is dependent on where it comes on the system. Like we're building Phase 9 because the product is coming on at a part of our system at the end where we don't have quite enough capacity. So sometimes you still have to deploy a bit of capital depending on where that product comes on. So I'll open it up to my colleagues here to add some color.

[J. Scott Burrows, Senior VP & CFO]

Linda, I would just add about 90% to 91% of our debt is on fixed rate. So 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 a short-term rate exposure at Veresen Midstream as well, but we've hedged 50% of that away. And as it relates to sensitivities, if you just bear with us 1 more month, we'll obviously lay out all of our sensitivities in conjunction with our 2022 budget. So that will form part of that press release.

[Linda Ezergailis, Research Analyst]

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

[Michael H. Dilger, President, CEO & Director]

Janet, are you able to speak to that?

[Janet C. Loduca]

Yes. 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. So I think we'll have to continue to evaluate. We do see that there's value to this asset in some way, shape or form. So I think more to come on that.

[Linda Ezergailis, Research Analyst]

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 industry versus partnering like we're doing with the Alberta Carbon Grid?

[Michael H. Dilger, President, CEO & Director]

Linda, we're -- that's a great question. Ultimately, assets ought to end up in the hands of the owners who can utilize them the best. So swapping assets is a terrific solution if they're respectively worth more to the other party. And so we're looking at things like that. We're looking at the ability to cycle capital maybe a little more than we than we used to. And so anything is possible, and we come into 2022. We'll talk more about that again in December, but extremely well positioned, generating a ton of cash with a low payout ratio, very low levels of depth and a machine that has a lot more upside than downside. So we're feeling really robust about what's possible coming into next year.

[Operator]

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

[Benjamin Pham, Analyst]

I wanted to ask a question on M&A and curious what the activity you're seeing, your appetite or the more slowing sellers out there given improvement in asset values and -- or other geographies that you're looking now that you haven't looked before? I mean, I'd love more high-level comments on M&A.

[Michael H. Dilger, President, CEO & Director]

Yes, sure. We tend to like to grow with connected assets or assets that are virtually connected through contracts. So what I mean by the latter comment is we're not physically connected to Prince Rupert, but we have long-term rail deals that make it so, so we consider those still connected and vertically integrated. And the reason we like to grow with connected assets is because as we offer services in the field to customers through the value chain, there's always some part of the value chain that is -- has spare capacity like in my response to Linda. If we got a huge new NGL contract because Dow needed ethane and let's say, it's C2+, we built a field facility, that would be new capital, but it could flow on our pipe without capital. And so the contribution to our pipe would go right to the bottom line, maybe we need to build a new frac, but we have extra storage. We have surplus rail for the C3+ and we're pipeline connected to AEGS, so no capital there. So you could see in that collage, some activities need new capital and some don't. And the ones that don't add exceptional profitability, some of which we can share with customers. And so we can make nice profits and customers can have better netbacks. And so that's the reason we seek that connectivity.Now if we had a storage terminal in Europe, it's hard to imagine how 1 plus 1 equals 3 there. So we tend to shy away from that. And we've also learned that building from a position of strength and assets and customers. We know Pat's question about what's possible downstream of alliance? Well, we're down in Chicago. We have major assets there. So we have familiarity with that business. So that would be a good example of places where we could look, where we have knowledge and experience and advantage. And so that really has and will continue to guide what we do next.

[Benjamin Pham, Analyst]

Okay. And then my second and last question is on Ruby. The post contract financial contribution, is that tracking in line with your expectations? Your initial expectations, it wasn't.

[Michael H. Dilger, President, CEO & Director]

I don't -- I'm not sure I understand the question, but I'm going to turn it over to Harry, maybe he understood and he can answer it.

[Harold K. Andersen, Senior VP & Chief Operating Officer of Pipelines]

Yes. Generally, yes, and Cam can give the specifics.

[Cameron Goldade, Vice President of Capital Markets]

Yes, Ben, I think, obviously, the producer contracts rolled off at the end of July. So Q3 was a pretty decent run rate for Ruby going forward. There's 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. But I would say that where we're at, balance of Q3 and into Q4 is sort of going to be the run rate for Ruby.

[Operator]

And that concludes today's question-and-answer session. I'll turn the call back over to Mick for any additional or closing remarks.

[Michael H. Dilger, President, CEO & Director]

Well, thanks, everyone, for your questions. We do have to jump to. We have an employee town hall, lots of interest, I can tell. We rarely take the full hour. So thanks for your interest. We've got a lot of tailwinds right now. Existing assets are king. And our customers are healthier than I've ever seen them and sky's the limit for them. And hopefully, that will turn into volumes soon and drive our activity forward. Looking forward to providing our updated '21 insights in December and further look into 2022 at the same time. So with that, thank you very much, and have a great weekend. Goodbye.

[Operator]

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