Good morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation's 2022 Third Quarter Results Conference Call. [Operator Instructions] This call is being recorded on Friday, November 4, 2022. I would now like to turn the conference over to Cameron Goldade, Chief Financial Officer. Please go ahead.

Thank you, Colin, and good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the third quarter of 2022. On the call today, we also have Scott Burrows, President and Chief Executive Officer; Jaret Sprott, Senior Vice President and Chief Operating Officer; and Janet Loduca, Senior Vice President, External Affairs and Chief Legal and Sustainability Officer. I would 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's Discussion and Analysis dated November 3, 2022, for the period ended September 30, 2022, as well as the press release Pembina issued yesterday, which are available online at pembina.com and on both SEDAR and EDGAR. I will now turn things over to Scott to make some opening remarks.

Thanks, Cam. In the third quarter, Pembina delivered strong financial results, highlighted by adjusted EBITDA of nearly $1 billion. As with the prior two quarters of this year, the third quarter benefited primarily from rising volumes on key systems and strong performance within the marketing business. We benefited this quarter from a wider Chicago-AECO gas price differential and a wider condensate price differential between Western Canada and the U.S. Gulf Coast. However, while commodity prices and differential certainly works in our favor, overall, the quarter was a great combination of volume-driven results in the base business and tailwinds in the marketing business. We are pleased that stronger-than-expected year-to-date results have allowed us to raise our 2022 guidance again with full year adjusted EBITDA now expected to be in the range of $3.625 billion to $3.725 billion. Along with strong financial results, the quarter was punctuated by the closing of the transaction to create Pembina Gas Infrastructure or PGI, with our partner, KKR, and the 3.6% increase to Pembina's common share monthly dividend. The integration of PGI is going well, and we look forward to realizing the benefits of this transaction. We see tremendous opportunity to enhance utilization across PGI's asset base and look forward to working with KKR to pursue future growth opportunities through this premier Western Canadian gas processing entity. In fact, a key area of focus at Pembina over the next 12 to 24 months will be growing cash flow by increasing utilization at all of our existing assets, gas plants, pipelines and fractionation facilities. This is highly accretive growth given the modest capital spending required. As volumes grow, Pembina continues to have success signing new long-term contracts. In addition to the previously disclosed commercial agreements recently signed with three leading Northeast BC producers, Pembina has successfully contracted…

Thank you, Scott. As Scott noted, Pembina reported quarterly adjusted EBITDA of $967 million, representing a $117 million or 14% increase over the same period in the prior year. Relative to the prior period, the third quarter was positively impacted by stronger marketing results due to higher margins on crude oil and natural gas sales, and a higher share of profit from Aux Sable, partially offset by lower NGL margins as a result of lower propane prices and higher input natural gas prices; likewise, a combination of higher volumes on the Peace Pipeline system and higher inflation-adjusted tolls, a higher contribution from Alliance Pipeline, higher contribution from the PGI assets and a lower realized loss on commodity-related derivatives. These positive factors were partially offset by a lower contribution from Ruby Pipeline and higher integrity costs. Notably, in our marketing business, we typically see a lower contribution in the third quarter due to the seasonality of our NGL business. However, this quarter, Pembina benefited from a favorable oil price environment and certain price differentials that led to an outsized contribution from the crude oil marketing business, which more than offset the typical NGL seasonality. Earnings for the third quarter were $1.8 billion, representing a $1.2 billion or 211% increase relative to the same period last year. In addition to the factors impacting adjusted EBITDA, excluding the impact of a lower contribution from Ruby, earnings in the third quarter were positively impacted by a $1.1 billion gain on the PGI Transaction, lower income tax expense as a result of the PGI Transaction, and a higher unrealized gain on commodity-related derivatives related to NGL and crude oil marketing. Facilities results were negatively impacted by a lower share of profits from equity accounted investees due to higher depreciation, interest expense and an unrealized loss…

Thanks, Cam. At Pembina, we are fortunate that our industry-leading midstream footprint affords us the opportunity to engage with most producers within the Western Canadian Sedimentary Basin, and therefore, we are uniquely positioned to gain valuable insight on industry dynamics. In addition to the current volume growth, we are seeing on many of our key systems, we continue to observe significant positive momentum that we expect will ultimately result in producers sanctioning new developments leading to significant additional volume growth in the basin. We see several positive developments within the Montney, the Duvernay and the Clearwater as examples, and we continue to have a high degree of optimism regarding future base and activity, and corresponding growth opportunities for Pembina. Through three quarters of the year, results have been outstanding. And we are on track to deliver another record financial year, returning capital to our shareholders while pursuing opportunities that will benefit Pembina and its stakeholders in the coming years. Thank you for joining us this morning. Operator, please go ahead and open up the line for questions.

[Operator Instructions] Your first question comes from Jeremy Tonet from JP Morgan.

This is Steve McGee on for Jeremy. I guess just starting out on the guide, you hit on it a little bit there, but I just wanted to see if there's anything that we should think through on the other side on facilities and pipelines. Is there any downtick there? Is it purely just marketing going down?

Yes, so let me provide some context there. First of all, I'd say obviously, we raised the guide by $50 million on each end. I think -- at this point, our outlook is that we'd likely be trending towards the upper half of that guidance range. When we look at the business, first of all, on the Marketing segment, I mean I think you look across the commodity complex and pretty much all the spreads were deeply in the money for Q3. When you compare that to Q4, the curves across the board almost universally show compression, whether it be crude, NGLs or gas spreads. On the NGL side, we were adding inventory during Q3 at levels that are, obviously, in excess of where the prevailing prices are today to the tune of 20% to 30%. And last year, we saw what an important quarter Q4 is for the full year results. So with all those factors in mind, that was the biggest piece of it. I would say in the rest of the business, there are some puts and takes. I mean, obviously, we've got the benefit in the fourth quarter of a full quarter of the PGI Transaction and the PGI incremental contribution. It's a bit of a tailwind. We did have some sort of more unique or circumstantial wins in the pipelines business in Q3 that did offer another tailwind there that our current outlook would see normalizing. And when you roll all those factors together, that's where we got to on the revised guide.

Okay. Great. And then just hopping over to KAPS with PGI now fully in. I guess the next thing to look for is the KAPS sale. Just wanted to see progress on that. What are you thinking about proceeds there? Where do you see them going? Could this go more towards buyback authorization? Is it -- just how are you thinking about that aspect of it?

Yes. Thanks, Steve. I appreciate everyone is quite interested in the outcome of this. I think what I'll say and stick pretty tightly to is that the KAPS sale is pressing. And until there's a signed agreement, we probably don't have much more to say on it, just out of respect for the process and all parties involved, but it is progressing along nicely. Colin, is there more questions on the line?

I apologize. Sorry, I had a brief technical issue there. Yes, we have another question from Rob Hope from Scotiabank.

Questions on the next potential frac at Redwater. With what is a stronger-than-expected volume outlook, some contracts in hand, as well as your existing advantaged land opportunity there. What else do you need to see before you want to sanction that project?

Rob, Jaret here. Yes, great point that you just made. We obviously do believe that we obviously have a really competitive advantage here to provide our customers a great opportunity to expand fractionation. You mentioned the land. We wouldn't require any incremental spec storage and/or inlet storage. We've got the unit capabilities today. We've got high complex utilization that obviously keeps our customers' OpEx per unit extremely low across the entire complex. And then it gives us significant flexibility around outage planning, having four fractionators with significant storage being able to accommodate our customers' volume. So we do think that we have a really good solution for our customers. What we need to see, Rob, is we're just going through the process of firming up and extending some of the base contracts. You may recall that RFS II and III, I think they were around 2016, 2017. So wanting to firm up a little bit of that base and push that out, get a little bit more tenure there. And then just we're refining the capital as we speak. So that's kind of where we're at right now, but those are kind of the two triggers. Let's get the capital in line. Obviously, there's been some inflationary pressures. So we're working really hard on to offset those by different construction practices, procurement, contracting strategies, et cetera, and then firming up that base.

All right. And then just on the volume outlook, yes, you are correct, the 5% volume outlook, I would say, has been a nice surprise in 2022. When you look into 2023, kind of what are the tailwinds and headwinds that you're seeing for further volume growth? We did see a little bit of pipeline constraint on the gas side there through the summer. But how long do you think you can get this above-average volume growth to persist?

We are seeing that continued strong volume. Like it's kind of that slow and steady increase. I think if you were to see some potentially step changes would be -- and Janet could speak to this more if there's more clarity required, but the Blueberry River First Nation resolution, obviously, we have some strong dedications in and around that area. So that could be a step change. But regardless of the step change, Rob, we're just continuing seeing that strong drilling performance and a lot of wells being drilled, right? So it just keeps coming. It's not any 1 organization or a customer that's really focused. It seems to be a multitude of all of our customers just continuing to grow at a fairly moderate pace.

Your next question comes from Robert Catellier from CIBC Capital Markets.

Just a quick question. I just want to make sure I understand the motivation to sell your interest in E1 and E6. And how does that really change your frac spread exposure? And does it -- is there any interplay there with PDH? For example, you have lost access to propane that otherwise could have been used for a PDH facility, either your own or a third party?

Great question. So this is a little bit complicated, so just bear with me. We had -- so what we did was created a win-win solution with our partner at the complex. So we had working interest capacity in a third-party non-operated facility that commercially, it was extremely hard to access due to various reasons. So what we did was we got together on a cashless transaction, and we essentially sold down our working interest ownership, but we -- in return, we received a long-term, we'll call it, a virtual processing agreement. So actually, the physical volumes that we'll be extracting liquids from across that virtual processing is in excess of what we typically would have processed across that asset. So it's a long-term deal. And what this will also do is provide the owner -- now they're the sole owner of that entire site, it will allow them to optimize the facility to drive efficiencies, specifically around the operating cost side of the business. So it's not a straight up disposition of working interest capacity. In return, we received incremental virtual capacity. I hope that makes sense.

Yes, I think it does. I'm just curious, so is your frac spread exposure increased as a result of this? Or is it effectively unchanged?

It's very slightly modestly, it's increased.

Okay. And then we've had news of kind of tax coming eventually on the -- on share buybacks. I'm wondering how that impacts, how you're looking -- I know it's early days, but how you might look at returning capital to shareholders or other allocation priorities?

Rob, even -- it's Scott. Even before yesterday's announcement, I think you heard on the call today and messages over the last couple of months that with where we're seeing rates going and with our optimism around potential future projects, incremental free cash flow in the near term here is going to go towards debt repayment, both obviously with the rising cost of debt, but also in preparation of hopefully a build-out in '23 and '24. So it's not like right now, we're allocating significant capital in '23 and '24 to share buybacks where that may be an issue. So for now, it's a bit of a moot point for Pembina. Obviously, that could change. But for now, I think our allocation priority is towards debt repayment.

Your next question comes from Ben Pham from BMO.

On potential KAPS proceeds, are you actually able to or plan to take out the proceeds into Pembina for that? Or is that all staying at the PGI level?

Yes. The proceeds would likely be dividended out to the partners.

Okay. Got it. And then on the frac expansion opportunity, should we think -- or is there something to think about in terms of restrictions on market share in that frac business, the Competition Act? Is that -- is there restrictions on that market share, just level of ownership?

No, this is a new build with third parties freely signing up for this capacity. So we don't see any issues with that at all.

Okay. So not a situation in you had a couple of parties running fracs in the province and then there's certain percent market share, there's no restriction that you know of?

No.

Okay. And then maybe lastly on Cedar LNG. I'm wondering you have -- there's some noise around this competing LNG export project north of that, I think, with facing some adjacent First Nation challenges. Is that something you're hearing with your project in particularly adjacent First Nations around the area?

No, we're not hearing anything of that sort.

Your next question comes from Linda Ezergailis from TD Securities.

I'm wondering if you could just help us understand a little bit in this dynamic environment. When you're thinking about your dividend policy and balancing growth, sustainable growth in the dividend versus retaining free cash flows to finance projects. How do you balance that? And can you give us a sense of, over the next couple of years, as you're looking at some of the opportunities, what your thoughts are on the guardrails around that?

I think, Linda, the approach to dividends has been relatively consistent, I think, over the past few years, and it's always obviously been anchored around the fee-based business. So if you use 2022 for a moment as an example, obviously, we saw outperformance in the marketing business throughout the year and really that cash flow, as we said, was redirected towards both share buybacks and debt reduction. What we've looked for previously for consistent dividend growth is, the reliance on the fee-based growth in the business. I think we obviously have been through an interesting time over the past two or three years here. And obviously, we'll be out more formally with our guidance in December. But the environment is quite constructive, obviously, and as you can hear from the comments that Jaret and Scott are making on some of the project opportunities that we have that we do have ample fee-based opportunities in the portfolio, which should continue to support that trend into the [future].

And maybe just also -- and I don't know you're able to provide this today or maybe when you provide guidance. Would it be possible to get in aggregate a sense of your views on your aggregate direct commodity price exposure? And any key sensitivities recognizing that they might be imperfect, that would be very helpful.

Yes. I think we'll certainly provide that information for 2023 in December in our budget release or our guidance release. For now, I think we've provided that information back in the 2022 guidance release for this year. And I think the way we think about it is, obviously, the Marketing business contains our commodity-exposed cash flow. The pipelines in the facilities business are fee-based businesses. And so that would be a fair way to think about the delineation.

Your last question comes from Robert Kwan from RBC.

Just starting on volumes, you noted that ex some of the runoffs that volumes were up 5% year-over-year in Q3. So I'm just wondering, has that trend continued into Q4, but where are volumes sitting on your core systems versus the minimum take-or-pay levels?

Rob, yes, I would say that it obviously varies by business. If you sort of look at the frac business to start with, maybe backing up from there. Obviously, the frac business is running very high utilization. And you'll recall that the fracs that we built in the 2016, '17 timeframe were essentially 100% take-or-pay. So we're running right up against those. On the conventional business, it does vary according to segment. But if you look at the capacity, which we've talked about in really at the Fox Creek region, we're running right around the take-or-pay levels. We have been running just shy of them. And as we've seen sort of, obviously, Jaret's comments to continued and modest growth, we're sort of bumping right around those. And I think you can see that as in some of the disclosure around our take-or-pay recognition, particularly in this past quarter. If you back up from there and start to look at the gas business, I would say it's a similar story, generally speaking across the board, varies from facility to facility. But with those facilities that have a take-or-pay component to them, which would be the legacy Pembina facilities now sitting in PGI, again, we're running right around take-or-pay levels in those businesses -- in those assets like in aggregate.

Got it. So in short, it sounds like where a lot of the volumes are growing in the basin were kind of now in the cusp of starting to see that a little bit more directly in the results. Is that a fair characterization?

I think that's fair, yes.

Okay. Just turning to guidance. I know you said that you're trending to the top half of the range. But you've got $100 million top to bottom, which is pretty wide with 1 quarter to go. I'm just wondering, is that just being conservative? Or are you seeing some things in the quarter whether that's being less hedged or what have you, that's being more volatile than usual?

I think it's a fair comment, especially as we sit here on November 4. Keep in mind, we haven't seen our October results just yet. We're a few days away from that. And we're just recognizing that. Obviously, we saw what Q4 was for Pembina last year in 2021 and how, obviously, a sharp change in the price environment in Q4 really led to a performance in that year. I think we just recognize that clearly, there's a lot of volatility and a lot of external factors influencing markets right now across the board, both commodities, currencies, interest rates. And so it's a fair comment that the range could be perceived as a little bit wide with a quarter to go here. I think we're just reflecting that there's -- it's a wild world right now, and we just want to make sure that we're appropriately capturing that.

Got it. You mentioned currency. But just within the commodities, is there any particular spread that you'd point to that you're most not concerned about, but where you might have more exposure or maybe the range of outcomes is wider?

I think it's just -- it's a bunch of different things. I mean, obviously, and I sort of mentioned it in a prior comment, but if you look at, say, for example, the AECO-Chicago spread, that was shooting the lights out really in Q3. And if you look at where it is today, I mean, I think the current forward curve has at roughly half of what it was in Q3. Similarly on the sweet crude environment, those spreads went from areas where there was more opportunities, more optionality. They've certainly narrowed into Q4. Obviously, with the heavy spreads still staying wide, it would suggest that those opportunities would remain and that's not really much of our business. It's more so indicative. And then clearly, just back to the NGL price environment for a second. To my earlier comment, we've been putting inventory into the caverns throughout Q2 and Q3 at levels which are 20% to 30% higher than we're seeing in Q4. So just a bunch of those factors together just lead us to create some width to that guidance range.

We do have another question. This is from Patrick Kenny of National Bank Financial.

Just back to your comments around prioritizing debt repayment into next year. We've seen some of your peers sell down a minority stake in certain mature assets, which although might be slightly dilutive financially, wouldn't be very accretive to your social license as an operator, and again, raise some cash for paying off maturing debt. So I'm just wondering, as you look ahead at the strategy for 2023 and beyond, how important you think it is to execute minority interest transactions with various stakeholders across your legacy portfolio of assets as a key part plan overall value for the company?

Thanks, Pat. I think starting off, we're pretty proud of the two indigenous partnerships that we have today, and we think we're working really well with our partners and looking to build and grow those partnerships. So we feel like we've made good progress on that front. As it relates to asset sell-downs, I mean that's always a tool in a toolbox and something that we consider, whether it's outright dispositions or minority sell-down. So nothing is on the docket right now, but certainly, it's something that we run in our scenario analysis and talk about internally. But I do think as we sit today, we're pretty happy with where the balance sheet is. So there's no need to do anything like that. But there's always the opportunity if there's financial benefits or intangibles that come along with it. So on the drawing board, but nothing that's in active negotiations or discussions.

Got it. And I guess as a segue to the Nipisi pipeline, apologies if I missed it, but would you be looking to bring in a partner for that system as well if you do reactivate? Maybe you can just remind us, I guess, back in the day with the revenue or EBITDA profile looked like on Nipisi, what the capital requirements might look like to reactivate the system going forward?

So great question, Pat. So right now, we're just in the throes of executing some preliminary work to reactivate that pipeline. We're fairly bullish on the Clearwater, obviously, everyone's seen the results, but we expect to have that pipeline in service kind of like Q3 of next year. We do require some capital. We're just working through that right now. Just some integrity digs, some normal course and then some different tie-in options once that pipeline gets into Edmonton. Currently, we have not explored the reactivation with a partner. But we are working at this partner as you were asked, but that's not to say that's not out of strategy or in strategy. It's just focused on the execution and getting it back online here right now. And then I think you had a question, Pat, around the EBITDA. I think it was around roughly $32 million to $35 million of EBITDA, the full run rate prior to shutting down.

And directionally, I guess if it does get reactivated, cash flows above or below historical contributions, too early to say?

I mean I think ultimately, our goal would be to get back there and to exceed it, but it's not going to happen in year one. It will be a ramp.

There are no further questions at this time. I'll turn it back to Scott Burrows for closing remarks.

Thank you, everybody. Thanks for taking the time on a Friday to listen to our call. We're really proud of the results. And just before I sign off, I want to say thanks to all the staff on the phone and to everybody that were involved in the quarterly results, it's just a fantastic quarter. So thanks, everyone.

Ladies and gentlemen, this concludes your conference call. We thank you for participating and ask that you please disconnect your lines.