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.
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 4th, 2021 for the period ended September 30th, 2021, which is available online at pembina.com and on both SEDAR and EDGAR. With that, I'll now turn things over to Mick.
Great. 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 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 CAD 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, set 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 a lower carbon economy. In addition to the GHG target, Pembina expects to make further ESG progress with the announcement of a 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 polyethylene cracker in Fort Saskatchewan, Alberta. We estimate over 100,000 bbl 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 seasons 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 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 bbl 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 this 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 CAD 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 CAD 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 CAD 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. We benefited from higher volumes at Veresen Midstream's Dawson assets and on the Peace Pipeline system.
Offsetting these positive factors with the impact of a lower US dollar exchange rate, a lower contribution from Ruby Pipeline due to lower contracted volumes, lower revenue from Goshen 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 a change in Pembina's share price. Third quarter earnings of CAD 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 CAD 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 an 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 CAD 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 MMbpd 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 NGTL 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 volumes 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.
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 CAD 3.3 billion-CAD 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, operator, we'll wrap things up and go to questions. Thank you.
Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll take our first question from Rob Hope with Scotiabank.
Morning, everyone. First question's on the Alliance recontracting. Can you add a little bit of color here? Because the ARC7 contract expires at the end of October, so you had a big gap there, so did you just really recontract those last two months? Then I guess, you know, as a follow-up there, just given the strong demand you've seen, you know, why not look to extend those contracts a little bit further?
Rob, I'm gonna pass that over to Harry.
Hey, Rob. Good morning. To be clear, there was a renewal at the end of October for contracts that would expire in November 1st, 2022, for basically the 2022-2023 gas year. When Mick was going through his opening, what we spoke about in terms of Alliance essentially being full for 2022 were the contract expiries that happened October 31st, 2020. 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, that's helpful. You know, just taking a look at your LPG export terminal, we've been tracking the shifts in and out of Prince Rupert. It seems it's very busy there. When we look at the potential expansion into Q1 of 2022, is this really just, you know, wrapping up engineering because you're at a high utilization? Secondly, you know, what about, you know, moving other products out of there rather than just propane?
Jaret?
Good morning, Rob. Yeah, essentially, we're just wrapping up and getting to class three estimates on the expansion, so doubling the capacity and moving to the medium gas carrier. So essentially doubling the cargos that we can move through there versus the handies right now. We expect to make that decision in Q1 of 2022.
Is the thing that you have enough propane to export, so you don't need to touch butane?
Um, we're looking... We-we'll, we'll.
Okay.
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, you know, the positive feedback we've gotten on our product quality.
Yeah. Thanks, Mick. Rob, pardon me. So we've had, you know, 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 rail cars to our PRT site. We've moved 3.3 million bbls of propane through the facility in that, you know, -month period here, essentially. You know, we're really excited about, you know, the future and the growth. We've got cargos into Japan, South Korea, China, and Mexico, and we did our commissioning cargos into Hawaii, and so we're really happy with where the destinations have, we've been able to penetrate or move into the market.
One of the things that we're excited about is, again, our operating teams, you know, we're producing a low-ethane propane, and in particular, we have a very exceptionally low methanol content, which is rare, 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, you know, 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.
Thank you for the color. I'll jump back in the queue.
Go 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 East NGL System, perhaps Vantage? And also, does it make sense to strip off some ethane from Alliance at Fort Saskatchewan? Just wanna get a better sense on how you're thinking about feeding Dow that incremental supply over time.
Hey, good morning, Pat. I'm gonna just make a quick comment then turn it over to Jaret. As you know, we have ethane extraction assets all over the province. We're just sorting through the portfolio and frankly the diversification that our customers are asking for. They're not asking for just one source. They want diversified, geographically diversified product for obvious reasons. They're putting billions into the ground, and they don't wanna be beholden to one supply source. Jaret, maybe you can add some color. Thanks.
Yeah, you bet. Thanks. Good morning, Pat. Yeah, like Mick said, we're just currently evaluating all of the pipelines that feed our current customers, Pat, so between East and Vantage and the Peace system, et cetera, and evaluating the Redwater complex on where do we need to expand to provide our customers with that diversification that Mick talked about. They wanna ensure that the C2 molecules, their feedstock, are coming from a variety of sources. 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.
Working with our you know our fantastic partners over at Enbridge, we're currently evaluating that as well to not only you know satisfy existing demand, but also as part of the new expansion that you know potentially might be coming for the province.
Okay, that's great. Thanks for that color, guys. Just maybe a quick follow-up on Alliance, but more from a longer-term contracting perspective. Curious to, you know, 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 would you have to look at M&A, more strategic partnerships downstream? Thanks.
Yeah. Pat, it's very insightful question. It's like you're giving us tips on what to do next, but thanks for that. Yeah. You know, a bunch of this gas is making its way to the Gulf Coast, and with $20+ an MCF product, you can imagine why. Stu told our board yesterday that, you know, there's a better part of 10 Bcf a day of new export capacity being developed on the Gulf Coast. Until more things happen, like our Cedar LNG project, albeit that goes to Asia, we think there's gonna be a continued desire for shippers on Alliance to get to the coast, and certainly that's caught our attention.
That is under review. I think some of the, you know, 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. You know, it took us a few years to digest Alliance. I think there is, you know, possibility with Alliance to really put a lot of gas into that line and to look downstream as we have for, you know, where does the ethane go? Where does the propane go? Where does the methane go and keep our vertical integration going downstream. I know Stu's team's looking at that.
Great. Thanks, Mick. I'll leave it there.
We'll take our next question from Shneur Gershuni with UBS.
Hi, good morning, everyone. Maybe just wanted to start off kind of on the marketing business and how you're thinking about it for 2022. You know, commodity prices have obviously changed dramatically over the last three-six months. Frack spreads have kind of opened up as well. Do you expect to continue a hedging program and would it be programmatic 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.
You know, the thing about hedging is it's only hedging if you do it, you know, with regularity and consistency. In terms of trending, you know, we said in the notes that we're quite or very optimistic on what can happen next year in marketing. That is across the board. We also said in the piece that all commodities are doing well, and I think you're seeing our customers' quarterly releases are, I mean, jaw-dropping and possibly even better in the fourth quarter.
When they're making money across all commodities, it certainly helps us to make money and the differential pricing that we need to have, you know, really good outcomes is in place today. It's shaping up good. I think we're, you know, we've taken some risk off the table, and we intend to follow our normal process because, you know, 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 because many of our arbs depend on more than one commodity, as you know, and so we have to be cautious.
We do intend to keep following our systematic program of hedging.
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. You know, as part of the conversation or announcements at the time, you had talked about, you know, 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, need a thicker steel wall and pressure and so forth. Just wondering, you know, 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 about from a capital perspective?
Yeah. I'll start out and then kick it over to Stu. There's a couple things. Number one, we're looking at a combination. 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 gonna have the pressure capability that we need to move CO2. That's a situation where we could pull a line or 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-pressure gas pipelines, you know, we've done the work, and we think those pipelines can be retrofitted. They need some work. They need crack arrestors put in.
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. 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.
Sure. You know, again, I think you know, we have a vision, and as described, you know, we believe there is an advantage to our gathering systems that we have, and you know, you've highlighted is it rights-of-way or is it pipelines? We also believe as a pipeline operator that you know, we have expertise. We move you know, high-pressure pipelines and products. We do appreciate the difference that 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 some new pipe.
We will be you know, putting liners in other pipes and retrofitting some of our pipes, all in attempt to be, you know, to provide a CO2 solution at the lowest possible cost. We recognize, you know, we will be working with others collaborating on how to do that, where the emissions are gonna come from. We're working hard. We are part of the government of Alberta's process on the carbon sequestration rights that of the government is working through. We're working you know, with the government, with our partners, extensively with our partner on how to proceed, and we're excited about the progress. You know, we've got experts helping us along the way.
As the government's 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 will 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.
No, no, that makes perfect sense. I really appreciate the technical answer there. Thank you very much, and have a great weekend.
You as well. Thank you.
We'll go to our next question from Robert Kwan with RBC Capital Markets.
Hey, good morning. Just start with how you're characterizing the nature of the discussions you're having, you know, with producers. As you noted, they're holding or they're maintaining a lot of discipline for now. Just what's the pace or how's the pace of inquiries for new capacity and new projects been? Do you see a tilt in their thinking with commodity prices just trying to drill into existing capacity to take advantage of high prices quickly? Is there a growing willingness that you're seeing to make a long-term infrastructure commitment?
Robert, you know, 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. You know, even when the producers are allocating a ton of money to, you know, both of those activities, you know, I looked through some tables the other day, and the average net debt at the end of 2022 for the Canadian junior and intermediate sector and the U.S. sector is actually negative. On average, people across the sector are not gonna have debt. They're gonna have cash in the bank.
The only people that are gonna have remaining net debt are the seniors in Canada, and they're all meeting their targets. I read Cenovus' release. The question remains that these prices, you know, and with the economics of oil and gas well drilling, I mean, the silver lining through the horrible pandemic is, man, people learned how to do stuff at low cost. The economics of wells of activities have never been better. The question to me then is when. You know, there's lots of talk still out of COP26 and everything that is a headwind. 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. My prediction is, this is one man's prediction, when they can, you know, drill gas, drill oil with very fast payouts and with hedgeable commodities, that they're gonna start to take ground, particularly drill to fill situations. 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, you know, we've got Line 3, so there's no mystery about egress anymore. That was all a headwind.
I think that the things that can be done with relatively fast payouts will drive production up. What remains to be seen are there gonna be new SAGD trains and things like that happening, or is the industry just gonna 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. They look like they're gonna get better, not worse. I think OPEC is showing a lot of discipline.
Even there, you know, we know that there's hiccups from some of the smaller countries not being able to meet their their quotas and demand's returning. People are getting back on airplanes. I think things are looking very, very good from a cash generation perspective, and we have lots of inbound interest. I think it's not if, it's when. To your point, and the reason for your question is, this is more discipline than we've ever seen. Like, I'm a bit surprised that volumes and capital budgets haven't ramped up more significantly. It's just an incredible time, and the industry is making a ton of money, and they're shedding, I think, reliance on capital markets entirely. There may be good reasons for that.
I know that's a long answer.
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 2022 were in the range or even 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.
That's always a delicate question. Maybe Scott, you could take that one.
Yeah. Yeah, Rob, we added the 25% hedges kind of throughout Q2, so those would've been at roughly prevailing prices as it relates to Q2. Obviously since Q2, we've seen a continued increase and 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, you know, 15, call it CAD 15 million roughly out of the money. Then the 12% that we added was, you know, within the past several weeks here, so relatively close to where the spot pricing is for 2022.
Got it. Just on the overall above average commentary on marketing, like how are you calculating what's average for you?
I'll give you a coarse answer. Like, 2020 was like a P10 year, so you know, one in any given 10-year stretch, you know, in the bottom 10%. This year, given the strong second half and the way the year towards year-end looks, will be, you know, a P50. Like an average year. Next year, will be, you know, a very good year. I would say, you never know, Robert, like forward-looking information, you know. It could be a P75 year or better. We'll wait to see. Remember, it's not just one commodity, it's differential pricing that really is key in how we make money.
It's really difficult to predict one commodity versus another. If things were not to change from today's pricing, we'd have a very good year.
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.
Fair enough. Maybe just to follow on that, I know that's partly marketing, partly maybe facilities, but just any commentary as to what frac tightness, NGL kind of mix sloppiness, given the Plains outage and what that means both near term and into 2022.
Jaret Sprott, you wanna talk about, you know, where we sit, you know, how busy 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 backed up a little bit with some of the challenges that happened there in the you know late September. 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. You know, 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 you know very liquids rich, but still a lot of gas coming there, which is driving a lot of NGLs down through the value chain. They're all showing up in Fort Saskatchewan, highly utilized.
Thankfully everything's rocking and rolling with the assets, and we're seeing a lot of high processing rates. It's going well, and it's looking really good for you know. When you talked about, or maybe there was a question earlier about where are the customers 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 you know looking at RFS III you know going to the de-ethanizer there and going to 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.
Okay. 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, you know, 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, you know, green hydrocarbons at premium prices? Like, how do you think that fits into the Pembina story that you've got?
I think you're seeing real examples here. I mean, the Cedar LNG project, for example, is using green power. It's it'll probably be the greenest LNG in the world. I can't imagine how it would be better than that. That's obviously gonna be a coveted product. You know, 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. That's well underway.
We are looking at on a micro 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, you know, customers of the Alberta Carbon Grid, an 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. We've got a BCF a day of gross capacity there that's all run on green power.
You know, we're well down that road. We compare pretty well on a benchmark basis, and we're gonna keep taking ground. You know, those are the things that we're doing to put Pembina on the right footing and in the right direction. 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. You know, we've got most of our pipes in the province, as does TransCanada in terms of NGTL, both open access service providers that.
We're gonna 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 our storage, our capability. We need the pore space, the sequestration rights to be able to offer those services to customers. We look forward to doing that. We aspire to do that. You know, obviously where you put that stuff is really important to that equation. We'd love to have that in the Pembina store, and then we're gonna be users of that store ourselves.
That's very helpful color and context. I guess maybe just a follow-on, and it relates to, you know, on the sequestration side of it. You know, 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, into that industry?
Janet, do you wanna take a crack at that, and I'll add my thoughts after?
Well.
One moment. It looks like we have lost them for just a moment.
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 levels of government need to kick in to help producers, the emitters, capture their emissions. It's all well-understood technology Pembina knows and has experience with. It's capital intensive, 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 it will be good.
I think the projected carbon tax in Canada is way beyond what we see in the U.S. and, I think, almost anywhere in the world. You know, clearly, were that to come to pass, carbon capture could be economic.
Okay. That's very helpful. Thank you.
We'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 the MD&A about using rail transportation to position some propane at Corona. I'm wondering what you see in the fundamentals there to support that decision. 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?
Stu, maybe you and Jaret want to tag team on that.
Yeah, I'll start, and then Jaret can jump in. Rob, thanks for the question. You know, this is not uncommon for us. We actually have been using our current asset. We've railed products in. You know, we like the Sarnia market. We like the seasonality of the Sarnia market. We're coming into a valuable time. Yeah, the economics do justify you know, the cost to rail our product at this point in time. It's nothing new for us. We've done it on a regular basis. Jaret.
No, nothing further.
Okay. 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, you know, get back to normal operations there?
Jaret, maybe you can take the operating part, and Scott, if you wanna chime in on any financial things you wanna talk about there.
Yeah, Robert, everything's back to 100% operating on our side. It's been, I don't know, I would probably have to get the exacts, but it's been a couple of weeks now that everything's been back to normal for.
Yeah. 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 & Co.
Hey, good morning everyone. Thanks for taking my questions here. I just wanted to go back to Alliance, and if you could provide some commentary on how rates on the renewed 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 two. 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.
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 this, you know, a CAD 0.6 differential. You know, it's gonna move around. But our, and I know our partner Enbridge, our view has always been that's the best pipe from Canada going into the United States. And our outlook's always been very positive about that pipe. Harry?
Yeah. Thanks, Mick, and good morning, Matt. Just following behind Mick on the longer term outlook. Mick's right, 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 of 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. Long term, the structural advantages that Alliance enjoyed are still there, and we're actually seeing them to be a bit more robust. From a pricing perspective, I'll talk about in terms of the 2021, 2022 gas year.
The volumes that we fucked 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 working with the shippers up there. There's not much I can say, but we're expecting to have an update before the end of the year.
That's great. Yeah, thanks for that, Harry, and Mick. I have one on Cochin as well, probably firstly for Scott. Is that deferred revenue issue material and is that just a one-off? Previously you guys had been talking about adding, potentially adding more capacity and, Mick, as you've aligned bullishness on volumes here. Are conversations heating up there that capacity could be imminent as well? New capacity, that is.
I'll take this 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 of makeup rights and other things on our system. You know, it was less than CAD 10 million to the quarter. With that, maybe I'll pass it over to Harry.
Yeah. In terms of increasing the capacity, the Cochin discussions are ongoing. You know, obviously the condensate market in Alberta is very robust and I think we feel positively about the direction Cochin is going both from a volume and a price perspective.
Great. Thanks for that. Last one for Mick. Can you elaborate a bit more on you know there's some comments out there in the press about you seeing the benefit of combining some of the CCS projects out there and.
Some of the pushback we've been hearing is, you know, why pay a third-party a premium for that service, you know, and/or some of those other competing projects might be a bit more refined in scope. Would you mind just, you know, just touching on some of those key rebuttals and what your vision is for a broader system in Alberta?
Yeah. I mean, it's confusing how someone could say they would need to pay a premium given that our pipes are, you know, that we're proposing to utilize are 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 CAD 0.50 . On the dollar compared to new. Whereas other proponents need to build brand-new pipes. I can't really ascertain the root of that comment. Listen, if someone can do it less costly on their own, clearly they're gonna do it, and I guess we'll wait and see.
Great. Thanks for that.
Go to our next question from Linda Ezergailis with TD Securities.
Thank you. 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, you know, 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. From a model perspective as well, how might we think of inflation puts versus takes on the revenue side versus the cost side, in terms of any sort of commercial protections in place, and whether that inflation might actually prove to be a net tailwind for you next year?
Yeah, I'll take a couple of those. Starting with inflation, you know, when we think about scarcity of goods and services, you know, the number one thing is we've got to take good care of our employees, 'cause a lot of the scarcity we're reading about has to do with employees, and so we're very focused on that. You know, the next thing, regardless of cost is making sure you have all the spare parts you need. 'Cause as we're all learning in our personal lives, it's hard to get stuff right now. We've looked at having, you know, critical spares and spare parts and inventory across our systems.
In terms of the monetary part of inflation, number one, I think about three-quarters of our operating costs are passed through. We're obviously very cognizant that you know, those costs matter to our customers, and so we're doing everything we can to drive efficiency. We've literally put CAD tens of millions of efficiencies into our business since 2020, and that remains an ongoing focus of ourselves and our board. Lastly, you know, we observe that often inflation does correlate relatively well to commodity prices. 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 is gonna far outstrip inflation that we see on the financing side. Obviously, inflation can lead to interest rates and you know, we're really well hedged in terms of long-term interest rates. Maybe Scott wants to add something to that. Lastly, or second last, I'll open it up probably to Scott next. Where do we have leverage? We have leverage in Veresen Midstream. We have quite a bit of capacity there. We have leverage obviously on Redwater. 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 pipeline business.
You know, we are still operating in that business around three-quarters to 80% full. You know, tremendous torque on adding bbls there. You know, the places we're more full, as Jaret said, is on our frack business and some of our other gas processing businesses. Linda, we can run quite a while within our footprint. That sounds great, and it is great, but it also is dependent on where it comes on the system. You know, like we're building Phase IX because the product is coming on at a part of our system, you know, at the end where we don't have quite enough capacity.
Sometimes you still have to deploy a bit of capital depending on where that product comes on. I'll open it up to my colleagues here to add some color.
Linda, I would just add about 90%-91% of our debt is on fixed rate. We do have somewhere in the neighborhood of CAD 900 million that's exposed to floating rates, you know, we're looking at what to do with that here in the short term. We also have short-term rate exposure at Veresen Midstream as well, but we've hedged 50% of that away. As it relates to sensitivities, if you just bear with us one more month, we'll obviously lay out all of our sensitivities in conjunction with our 2022 budget. That will form part of that press release.
Thank you. On a separate note, some headlines recently that your Jordan Cove 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, you know, might others in the industry maybe find more value in that initiative or what are the moving parts?
Janet, are you able to speak to that?
Yeah. You know, this is Janet, and thanks for the question. You know, I think as we've announced previously, we paused the Jordan Cove development at this point. 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's value to this asset in some way, shape, or form. I think more to come on that.
Thank you. 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?
You know, Linda, that's a great question. You know, ultimately assets ought to end up in the hands of the owners who can utilize them the best. So, you know, swapping assets is a terrific solution if they're respectively worth more to the other party. You know, we're looking at things like that. We're looking at the ability to cycle capital maybe a little more than we used to. Anything's possible and we come into 2022, we'll talk more about that again in December.
You know, extremely well-positioned, generating a ton of cash with a low payout ratio, very low levels of debt and a machine that has a lot more upside than downside. We're feeling really robust about what's possible coming into next year.
Thanks for answering my questions.
Cheers, Linda.
We'll take our next question from Benjamin Pham with BMO.
Hi. Thanks. Good morning. I wanted to ask a question on M&A and curious what the activity you're seeing, your appetite or more flowing sellers out there, given improvements in asset values or other geographies that you're looking now that you haven't looked before. I mean, would love more high-level comments on M&A.
Yeah, sure. You know, we tend to like to grow with connected assets or assets that are virtually connected through contracts. 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. We consider those still connected and vertically integrated. 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 has spare capacity.
Like in my response to Linda, you know, if we got a huge new NGL contract because, you know, Dow needed Ethane or C 2+, we built a field facility, that would be new capital, but it could flow on our pipes without capital. 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 this, the C 3+ , and we're pipeline connected to AECO, so no capital there. You could see in that case some activities need new capital and some don't.
The ones that don't add exceptional profitability, some of which we can share with customers, and so we can make you know, nice profits and customers can have better net backs. That's the reason we seek that connectivity. Now, if we had a you know, a storage terminal in Europe, it's hard to imagine how you know, one plus one equals three there. We tend to shy away from that. We've also learned that you know, building from a position of strength, and assets and customers, we know Pat's question about you know, what's possible downstream of Alliance. You know, we're down in Chicago. We have major assets there, so we have familiarity with that business.
That would be a good example of places where we could look where we have knowledge and experience and advantage. That's really what has and will continue to guide what we do next.
Okay. My second to last question on Ruby. The post-contract financial contribution, is that tracking in line with your expectations, initial expectations and budget?
I'm not sure I understand the question, but I'm gonna turn it over to Harry. Maybe he understood, and he can answer it.
Yeah. Generally, yes, and Cam can get into the specifics.
Yeah. Ben, I think, you know, obviously the producer contracts rolled off at the end of July. Q3 was a pretty decent run rate for Ruby going forward. You know, there's been some short-term deals there that have backfilled some of the volumes on a short-term basis, but, you know, not meaningful contributors to revenue, just given the current spread. I would say that where we're at, you know, balance of Q3 and into Q4 is sort of gonna be the run rate for Ruby.
Aligning with.
Great. Thank you.
That concludes today's question and answer session. I'll turn the call back over to Mick for any additional or closing remarks.
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. You know, 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. Hopefully that will turn into volumes soon and drive our activity forward. Looking forward to providing our updated 2021 insights in December and further look into 2022 at the same time. With that, thank you very much, and have a great weekend. Bye.
This concludes today's call. Thank you for your participation. You may now disconnect.