Pembina Pipeline Corporation (PPL) Earnings Call Transcript & Summary

Good afternoon, everyone, and thank you for joining us. Today, this afternoon, we are very pleased to be joined by Pembina Pipeline's CFO, Scott Burrows, to walk through the Pembina story and engage in a Q&A session fireside chat. If you would like to ask questions, please feel free to put them through the system at any point, and I can enter them into the conversation. With that, I'm going to pass it to Scott, who has some opening remarks, and then we'll begin the Q&A. Scott?

Thanks, Jeremy, and thanks to yourself and to JPMorgan for hosting us today. As you'll see, there's been some slides provided through this conference. You can find them on our website as well. I do not propose to flip through those slides today, although I will in my opening remarks touch on aspects of most of those slides. And so you can follow along that way. But I thought it would be best to just kind of give you a high-level overview of how we're seeing things unfold and kind of how we see things kind of unfolding on a go-forward basis. And so not knowing who's on the audience and the familiarity with the story, I'm just going to go back a little bit in time. So for those of you that have been through this a few times, just bear with me while I get to some more recent commentary. But I thought it was important just to take everyone back to kind of early March at the start of COVID because it really sets the stage for some of the decisions that have been made and questions about how we see the next couple of quarters unfolding ahead of us here. And so as you may be aware, Pembina is one of the first companies to come out and take some pretty decisive action around maintaining the balance sheet and liquidity and responding to what was expected to be lower volumes in the relatively near future. So we ultimately deferred somewhere in the neighborhood of $800 million to $1 billion of CapEx in 2020 and deferred projects that we'll talk about in a couple of minutes in terms of when and if those might come on the books and some of the decisions around that. But that was one of the early moves that we undertook. In addition to that, we looked to take $100 million of cost structure out of the business, split relatively evenly kind of $50 million from OpEx and $50 million from G&A, ultimately trying to protect the guidance range that we had previously put out. And at that time, we also reiterated our guidance range, albeit at the low end of that guidance range. In addition to some of the decisions around capital, we also undertook shoring up the balance sheet with incremental liquidity. So we put in place an incremental $800 million revolving credit facility and really sized that appropriately to backstop any maturities that we had in 2021. Since that time, we've undertaken a 5-year term loan facility. That was USD 250 million. That was sub-2%. And because of access to capital markets opened up, we were able to capitalize on that by issuing another $500 million of long-term notes, weighted average of about 12 years. With some of those proceeds, we repaid the one maturity we had in 2020. That was about $75 million. And we're in the process of calling $200 million of our $800 million notes in 2021. So within the next couple of weeks here, we will only have maturities of $600 million in 2021 and feel pretty confident about the access to capital in the debt capital markets right now. So as we sit here today, we're sitting on about $3 billion of liquidity, which is ample for all the next several years' debt maturities and capital programs. So we feel very, very good from a liquidity perspective. At the same time, through the March and April time frame, we were going through our year-end ratings review with both S&P and DBRS. Unfortunately, for us, it's a good news, bad news story. It took a lot longer than we expected to get those ratings done, which was bad news. The good news was, really, it was pushed off by the rating agencies because the commentary was really around not overly concerned about our credit. We weren't close to their highest priority. So they just weren't that concerned about the credit concerns, and so it just took them longer to deal with some of their higher-priority accounts in terms of guys that were maybe a little bit more on the cusp of getting downgraded or did get downgraded. So subsequent to that March press release, I believe it was in kind of around late April, early May, we did get both S&P and DBRS confirming our ratings, and not only confirming our ratings but also both with stable outlook. So certainly, that was a good news story as well. We sit here today -- as many of you know, we still manage to our guardrails and we're firmly within our guardrails. In addition to risk, we continue to apply our systematic hedging program. And so as we look forward for this year, we are 50% hedged on our frac spread exposure, and we're already close to 30% to 40% hedged in 2021. So again, just continual actions in terms of taking risk out of the business where we can. As we sit here today, obviously, a lot of questions around producers, what's going on, on the producer front and what we're seeing. And so I think it's just -- it's nice to level-set a few things. I think, number one, as we -- again, just based on the latest data, we think we're over any kind of declines on the system. Obviously, with what's going on, there has been shut-ins in Canada and probably some natural declines from drilling slowing down. And we did see volumes drop over the last couple of months. I would say that that's -- we can see that that's bottomed out, and in fact, probably bottomed out in early May. And we started to see, since early May, those certain amount of volumes come back on to the system. So it's probably a little too early to say it's a recovery. But certainly, volumes are ticking higher marginally on a week-by-week basis. And I think part of what's driving that is -- and it's -- I think it's important to highlight the pricing dynamic in Canada. So we talk a lot about WTI and we talk a lot about Brent. But when you actually dive into Canadian pricing just in terms of the differentials and the FX, it has a pretty big impact on the producers up here. So when we look at pricing today with WTI in that USD 36, USD 37, really, what we're seeing on an Edmonton Light Sweet basis, it's kind of bounced around between that $46 to $48. And of course, Canadian costs are in Canadian dollars. So on a netback basis, we've seen a decent uptick from the producers. Condensate continues to trade at a very tight differential to Canadian lights, so call it, plus or minus $1. So again, those that have condensate exposure, they're seeing netbacks -- or not netback, sorry, pricing in the kind of CAD 46 to CAD 48. And then interesting is what's going on with WCS. We're seeing Canadian pricing of WCS at roughly CAD 40, which is an CAD 8 differential. And so it's important to highlight that because when you think back to when budgets were set earlier in the year, most people were probably using a differential that was more in that kind of $15 and probably USD 15 like -- U.S. dollar differential, which could be up to CAD 20. So that collapse in the differential down to, call it, $8, has had a pretty meaningful impact on the overall netback. You could argue that some of the heavy oil producers, their netback is almost probably in line with -- some of whom set their budgets depending on how conservative they were with that differential. So all that to say -- listen, these aren't prices that we think people are going to start drilling their brains out or bringing a ton of production necessary back online. But I think what it does highlight is some of that concern around credit or people getting into trouble, I think, has dissipated with the netbacks. Again, like I said, it doesn't mean people are going to deploy significant capital, but it does give us a lot more comfort around the credit than when we were seeing $20 WTI with actually like $5 to $10 negative differentials on Edmonton sweet. So a pretty wild swing in the last couple of months. And that outlook around probably not bringing back a bunch of capital and drilling really leads itself to a discussion for Pembina around CapEx, given the deferrals that we undertook. One of the most popular questions we get obviously is what does -- when does that capital come back? What's going to drive that capital coming back? How much is going to come back? And so when we think about that question, it's a hard question to answer. And I'll just walk you through the thought process because a black-and-white answer is not really clear at this point. And so as we sit here today, if we're in a weak pricing environment where we continue to see producers maintain production, slightly decline production, that probably means, from a Pembina perspective, we're in a low-CapEx world. And so if you think about a low-CapEx world, we always have the odds and sods, $10 to $25 to $30 million laterals and other projects that we're undertaking. There's some capital that we still spend once projects go into service just to clean up right-of-ways and other things. And so what I'm going with that is you probably have a couple of hundred million of capital, no matter what, in 2021. But in that scenario, our cash flow after dividends and after CapEx or a true free cash flow, we could be in a situation where we're generating true free cash flow, and then we can have the discussion around how best to deploy that free cash flow. If we're in an environment that stabilized potentially a little bit higher as we sit here today, there is a scenario where some of those projects come back online. And then we're more in that kind of free cash flow neutral perspective. And then obviously, if we're in a -- if the world changes and we're back in a much more positive environment and positive on demand and we see volume growth, obviously, the capital projects all come back and then we're in a more normalized or historical capital deployment mode. And so when we look at each of the buckets of projects, we really have to bucket them, I'll call it, into 3 different buckets. So the first bucket, I really call it kind of the discretionary capital. So whether it's our Prince Rupert expansion, our cogeneration facility, a few other small projects, that isn't big capital. But those projects ultimately are a capital deployment decision. Those are mostly either marketing assets or a reduction of Pembina's OpEx. So we really control that decision. And it's a decision around whether we want to deploy that capital or there's a better use for that capital. The next bucket is really the pipeline expansions. And so Phase VII, VIII, IX, those were roughly $1 billion in aggregate of projects and really adding significant capacity across the entire pipeline system. At the -- given the current outlook, it's probably a more realistic scenario where Phase VII, VIII, IX are almost reimagined and they come back in smaller increments, debottleneck certain parts of the system. And given the flexibility we have given our conventional pipeline system, we can think about how best to bring some of those phased expansions back into the fold. So VII, VIII, IX probably don't come back on the books as previously disclosed. They probably come back in some sort of reimagined phasing. But again, that's going to depend on volume growth and who's drilling and where it's drilling because that's really going to drive where there's potential debottlenecks on the system. And despite everything that's going on, there is the odd producer that is talking about meaningful growth. There was people that had capacity on VII, VIII, IX that still need some of that capacity. And so we're just working through all that. And then the last bucket really is CKPC, which is our petrochemical project. And really, that's much more of a binary decision. That project either comes fully back on the books or doesn't. There's no in between. There's no rephasing of that project or not. And so that project, right now, obviously, we're finalizing some long lead orders. We're suspending engineering and -- not operations, sorry, but suspending engineering and some of the equipment we hadn't ordered yet, and really creating an option value for that project as we step back and reassess a couple of things, number one, just the long-term impact on COVID on construction and some of the engineering and construction contracts that we have in place. Obviously, building that project on time and on budget is a huge priority. So understanding what that might look like in a post-COVID world is something that we really need to understand. We also need to take a pause and think about will the post-COVID world have any long-term impact on supply and demand for polypropylene. So there's a lot to work through on that project. I really -- just bringing it up because it is much more binary than some of the other projects, and the decision around that is obviously slightly different than the other buckets of projects. So Jeremy, I think that was about a 10- to 15-minute introduction. Really tried to hit on what are some of the more common questions that we've been receiving. And so I think, at this point, maybe I'll just pause and see if you have any questions that you wanted to fire over.

Thank you very much for that, Scott. I think you've answered all my questions. I don't have anything left at this point. But I'll try to work through a few questions here. And please, everyone in the audience, if there's anyone that does have a question, feel free to enter that into the queue, and we'll work that into the conversation. But maybe just kind of starting off, I guess. And you've kind of touched on different points here, but just wondering if you could clue us in like how your producer customer conversations kind of progress? Like the beginning of March, everything had completely dramatically changed, and then how things evolved to the point here where you have this comfort level that you said in earnings of hitting kind of the lower end of guidance. And it seems, based on what you're saying here, that confidence has only kind of increased. Just wondering, how is the tone from producers? What did you learn across process that gave you guys a good outlook here?

Yes. Good questions, Jeremy. The conversations with producers really evolved over time. Certainly, in March, there actually wasn't a lot of conversations. And I think, naturally, most people were shell-shocked. They were very inwardly-looking, slashing capital, cutting costs, trying to figure out this whole work-from-home environment and how all that works. Since then, I would say there's kind of 2 camps. There's people that really needed short-term liquidity or that's where their focus was. I'd say a lot of those conversations have died down just given what's happened with commodity prices in the depths of April when people were staring at $20, $10 WTI, negative netbacks. Like I think some of those discussions -- and by the time people worked through some of those discussions, commodity prices have rebounded and a lot of those discussions have gone away. And then there's discussions longer term around companies that are maybe changing their approach or their drilling program, who maybe are a little over their skis in terms of commitments. And so what we did was establish a commercial response team that's really assessing customer requests. And I think from kind of the get-go, we've kind of tried to say that we're not going to be the shock absorber for the industry. But that being said, we are only as strong as our customers. And so we are having discussions that range from blend and extends to areas of dedications, other things to help strengthen the overall contract. I think as a starting point, we look at who's the customer, are they strategic, are they important to Pembina's growth. We start with, it has to be at least NPV-neutral, if not positive, to make it kind of worth our while and to grab some of that relief. I mean, to date, there's been nothing really material at all granted, but there's ongoing discussions with various counterparties. We did reiterate in May that -- with our Q1, that we were still trending towards the low end of our guidance range. I'd say there remains some pretty strong headwinds when you think about is there going to be a second wave of COVID. Customer requests continue to come in about what's possible and what that might look like. Through this piece from March to today, AECO has remained very strong, which has led to a lot of strength from the gas producers. That started to lag off a little bit here, and so we're watching that pretty closely. A double-edged sword is NGL prices. We've seen a lot of strength in NGL prices lately. So people just naturally assume that Pembina should benefit from that. And I think there's a couple of points to make. Number one, we're 50% hedged. So while that protects us on the downside, we obviously don't participate on the upside as much as we would like. Secondly, as you think about the propane business, where the vast majority of the profit is made, you kind of sell 2/3 of your volume in the winter months and 1/3 in the summer months. So what you really want is, in this piece -- or this time piece, you want prices to be low because that's really when you're storing and keeping inventory low, and then you want it really high in the winter and selling it at high prices, right? And so that's where you make a lot of the money. But as you sit here today, we're adding inventory at a high price compared to the last couple of months. And when you look at the curve, there's not that much delta between pricing today and the winter months as we sit here today. And so that -- you have to look at your cost of your inventory to your selling price. And so my point I'm trying to make there is NGL prices are stronger than they've been in the last little while. It is a net positive, but maybe not to the extreme that people are talking about. Now that being said, we are seeing some tailwinds just in terms of U.S. dollar strengthening against the Canadian dollar, is a slight positive for us from when we set our budget given 20% U.S. dollar exposure. And then on the crude oil side, just with the higher prices, we tend to make a little bit more in our crude oil marketing business. So that's a positive as well. The discussions around volumes really are following our internal forecast and our -- how we kind of have predicted the world unfolding on our business. So when I say things like, we might have bottomed out and we're slowly ticking up, I would just take it as that's kind of following our expectations. It's not -- it's certainly not above where we thought volumes were going to be. So I wouldn't call it a tailwind. I would just kind of call it a net neutral.

That makes sense. And so maybe just kind of digging down to what you see right now as far as -- any color you can provide as far as the level of shut-ins today? And everyone's crystal ball is a bit buzzy these days. But looking forward, absent a second wave of COVID, kind of how you see things progressing at this point, should commodity prices play out per -- where the curves sit now?

You know what? It's -- I'm going to do my best to answer that question, but it's a little hard because I do -- I'm not sure people are being -- I'm not sure everybody is disclosing when they bring production kind of back online. And given our lack of oil egress pipelines, it's a little harder to see real-time data. I mean I'm sure Enbridge and TransCanada have a slightly better view than we do. But I think -- and it's also important to, I think, to break out shut-ins between true shut-ins and turnarounds because I think that the best estimates we have seen is -- it was probably in April and May, somewhere between kind of 900,000 and 1 million barrels a day of production. Arguably, 250,000 to 300,000 of that was accelerated turnarounds. I just think that's an important point because those were already factored into people's estimates. They might have just had it in Q4, but now they've been accelerated into Q2. So structurally, you're maybe only at that kind of 600,000 to 700,000 barrels a day of shut-ins. The next important fact to look at is what's actually shut in because to the extent it's synthetic crude oil, that really has, from a Pembina perspective, no impact because the cost of service nature of those pipelines and no indirect impact around condensate because it's obviously upgraded crude oil, whereas, the heavy oil has an indirect effect on condensate. And so what we spent a lot of time in March and April doing was kind of building up our view of shut-ins, and more so not actual shut-ins, but predict of who we thought would shut in based on netback, what would be the impact on condensate, where would the condensate shut-ins come in and then really look at the contractual underpinnings we had with those people. Because there's a difference between -- if the condensate that gets shut-in is above your take-or-pay, then we're only going to be impacted down to our take-or-pay. If the condensate that shut in is from a producer who is already below their take-or-pay, well, that's really no financial impact to us in the short term. And then, obviously, if it's on an interruptible contract, there's exposure. And so we really spent a lot of time around that exposure angle and just where we might see kind of the impact of EBITDA. And that's the exercise we went through in order to be able to kind of confirm the low end of our guidance range with Q1.

That's helpful. And you talked about NGL pricing kind of being a bit stronger now. But wondering if you could talk about condensate a bit here, how you see kind of supply/demand balance shaking up there. And having acquired Cochin, I guess, what more have you learned or what better viewpoint does that give you on the market at this point?

Yes. So our analysis show that roughly -- there'd be condensate impact of roughly 100,000 to 150,000 barrels a day kind of at peak and then coming back on the system as heavy oil came back. We were of the view that, that would be borne by the import pipelines and a little bit by the WCS -- or the WCSB producers. I would say, generally, as a rule of thumb, it kind of came in as we expected. And we -- there's been an impact on both the Southern Lights import pipeline as well as Cochin. Some subtle differences is the largest shipper on Southern Lights is BP, and they tend to use that more as a trading condensate line versus -- our shippers are much more -- and well, they are users of that condensate within their operations. But it's an interesting -- and it's kind of a tale of 2 worlds. When we acquired that asset, I mean, almost immediately, January through March, we were able to start to get after some of the synergies we predicted on that pipeline, including increasing the throughput on that. And so in Q1, we were shipping above our acquisition model in terms of volumes on that pipeline. Obviously, in the last couple of months, just given the lack of condensate demand given what's going on with shut-ins, the volumes on that have now dropped to below the take-or-pay, and so that kind of the acquisition model. So certainly, we're -- we've learned a lot in a short amount of time on that pipeline. I think it was a positive in the fact that we know that the synergies exist and we can capture it. Potentially, it's been delayed a couple of quarters here as we wait for volumes to come back on the system. Condensate in the WC assets has generally held in pretty well. There were some producers that shut in, but it was -- the condensate pricing in the last couple of months has been wild. I mean it's gone from $10, $15 differentials back to a premium. Crude was negative, and now it's on its side. So I -- it really felt like the producers were having a hard time making like a strategic decision around what to shut in or not. I mean there has been volume impacted as we talked about kind of March, April, May. But we are starting to see that come back on the system. And again, when you look at the differential, which I think is a good proxy, or if we believe in efficient markets, that differential should roughly represent the supply/demand of that product. And when I look today, it was at $0.25 differential, so essentially right on crude, which leads me to believe that the demand for that product is returning just as prices have strengthened.

That makes sense. And just wanted to see -- I think you talked about a $100 million of cost savings you're looking to get out of the business. And just progress on that. Has that been done? Has that kind of proceeded to plan? Or any other things you've learned as far as cost-saving exercises and other ways to tighten the business if it made sense.

Yes. So maybe just I'll start on the OpEx side, so roughly $50 million of OpEx. We're implementing that and we'll continue to implement that. So that will naturally just come in over the full year of the business. I think from a management perspective, what we're super focused on is ensuring that that's more of a structural change versus people just deferring costs into 2021. And so for the most part, we're really aiming to make those permanent structural changes. And so we continue to work through that. And some of it is just by the nature of it. But there was some costs where people are looking to put those back into 2021, and we're asking them to think differently about the business to make it a more structural change. The other $50 million was really on the G&A front. Part of that was we did have a round of layoffs. So naturally, that's a structural change that's happened immediately. That's happened. And so you can say that that's going to be implemented over the next year. You'll see that impact right away, offset a little bit in the short term by severance. So that's happened. There was a piece of that $100 million on the G&A -- on the $50 million G&A front, which is long-term compensation. That's tied to compensation plans and share price. We have seen the share price recover a little bit. So getting that full $50 million of the G&A, we're going to have to find some other buckets to come after. So long way of saying, part of the G&A was structural, part of it was kind of more of a 1-year kind of 2020 impact.

Well, Scott, I think I could sit here and ask you questions all day. But unfortunately, I think we've run thin on time here. But I want to say thank you very much for taking the time to go through the Pembina story with us today, and hopefully, we can do it again next year in person.

Yes. Thank you very much for your time. And for all those on the phone, appreciate you listening in and hearing our story. Thanks, Jeremy.

Thank you.