Plains Gp Holdings LP Q1 FY2023 Earnings Call

Good day, and thank you for standing by. Welcome to the PAA and PAGP First Quarter 2023 Earnings Conference Call. Please be advised today's conference is being recorded.

Thank you, Kevin. Good morning, and welcome to Plains All American's First Quarter 2023 Earnings Call. Thank you for all of you for joining us on our new time today. The new day and time for our earnings call is a result of feedback from many of you and part of our ongoing efforts to continue optimizing our engagement with investors and analysts. Today's slide presentation is posted on the Investor Relations website under the News and Events section at plains.com, where an audio replay will also be available following today's call. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on Slide 2. Highlights from the quarter are provided on Slide 3, a condensed consolidating balance sheet for PAGP and other reference materials are located in the appendix. Today's call will be hosted by Willie Chiang, Chairman and CEO; and Al Swanson, Executive Vice President and CFO; as well as other members of our management team. With that, I will turn the call over to Willie.

Thank you, Blake. Happy Friday, everyone, and thank you for joining us. Earlier this morning, we announced strong results, reflecting good progress towards executing on our full year '23 targets and providing us with confidence in our ability to deliver on the plan that we laid out in February. As a result, our comments today will be brief. It's been a volatile few months from a macro perspective with recessionary concerns, headlines in the banking industry, and an unexpected OPEC production cut, along with the ongoing war in Ukraine. Through all of this, we remain confident that Plains is well positioned for the long term as North American supply will continue to be critical to meeting growing long-term global demand. For 2023, and as illustrated on Slide 4, our focus is on execution. And through the first quarter, we've done just that, reporting adjusted EBITDA attributable to PAA of $715 million. As a result of our first quarter performance and our outlook for the balance of the year, we are reaffirming our adjusted EBITDA guidance range of $2.45 billion to $2.55 billion for 2023. Additionally, we continue to expect free cash flow generation of approximately $1.6 billion and common distribution coverage of 215%, which includes our recent $0.20 per unit annualized distribution increase. Looking forward, we expect that our continued focus on free cash flow supports our previously announced capital allocation framework, which targets multiyear annualized distribution increases of $0.15 per unit and further debt and leverage reduction. Al will share additional detail on our quarterly performance and 2023 outlook in this portion of the call. Let me shift to the Permian. We continue to capture increasing volumes on our system, and we expect production growth of plus or minus 500,000 barrels a day exit to exit in 2023 based on an assumed 2022 exit production of approximately 5.65 million barrels a day. While still relatively early in the year, current horizontal rig count is tracking in line with our expected full year average of 340 horizontal rigs, and we continue to monitor additional data points, including well completion activity and commodity price environment. Consistent with our February guidance and as shown on Slide 5, we expect year-over-year growth in our crude oil segment, underpinned by continued Permian production and tariff growth volumes in our gathering in our long-haul systems. Before I hand it over to Al, I wanted to reinforce that capital discipline remains front and center as we continue to advance capital-efficient NGL opportunities around our Fort Saskatchewan facility, which we expect to share additional detail on later this year.

Thanks, Willie. We reported first quarter adjusted EBITDA attributable to PAA of $715 million. This includes crude oil segment benefits from market-based opportunities and increased volumes across our systems, primarily within the Permian. The NGL segment benefited from seasonally higher sales volumes due to winter demand and favorable margins. Slides 9 and 10 in today's appendix contains walks, which provide more detail on our first quarter performance. A detailed overview of our 2023 guidance and key assumptions, which remain consistent with our February guidance, are located on Slide 12 within today's appendix. We continue to expect year-over-year growth in our crude oil segment, driven by anticipated volume increases in our Permian business. For the NGL segment, we remain highly hedged and continue to expect segment adjusted EBITDA midpoint of $420 million. I would note this reflects a more pronounced winter to summer sale versus 2022, which reflects lower volumes due to a planned third-party turnaround in the second quarter, the February sale of our non-op interest in the Keyera Fort Sas facility, and an NGL market structure that supports increased sales volume in the peak winter demand months relative to the summer months. Regarding capital allocation, as illustrated on Slide 6 and consistent with our February outlook, we remain committed to significant returns of capital to our equity holders, continued capital discipline, and reducing debt and maintaining financial flexibility. For 2023, we expect to generate $2.3 billion in cash flow from operations, $1.6 billion of free cash flow with $600 million of free cash flow after distributions available for net debt reduction, resulting in year-end leverage of approximately 3.5x. We will continue to self-fund $325 million and $195 million of investment and maintenance capital net to PAA, which is consistent with our February guidance and does not include amounts related to the potential Fort Sas opportunity.

Thanks, Al. Today's results reflect another quarter of strong execution, and we remain confident in our outlook for the year despite the near-term volatility. We continue to believe that the world needs North American energy supply long term and that our business is well situated to meet this need in a low-cost, reliable, and responsible manner. We also believe we're well positioned to meaningfully increase returns of capital to unitholders through our targeted multiyear distribution growth and 8.5% current yield, significant free cash flow generation, and balance strength as illustrated on Slide 7. We appreciate your continued interest and support, and we look forward to providing further updates on our earnings conference call in August. With that, I'll turn the call over to Blake to lead us into Q&A.

Thanks, Willie. Kevin, we’re now ready to open the call for questions.

Our first question comes from Michael Blum with Wells Fargo.

Wanted to talk about Permian growth. Curious if you're seeing any change in producer activity or messaging as commodity purchases pull back? And any updated outlook for Permian growth rate in 2023?

What I would say is a combination of activity, as William alluded to, 340 rigs are working, that's in line with our plan of activity, number of completion crews, number of connections in the first half of this year and the second half. Current volumes on the system imply roughly 40,000 to 50,000 barrels a day of growth necessary to achieve the 500,000 barrel a day growth range. In discussions with producers, we're in the band of inelasticity somewhere between, I don't know, if it's 65% to 85%, but it doesn't seem like producers move rigs one way or the other on the crude side. Gas has kind of gotten out of that, and you've seen some gas rigs move off. But by and large, we don't see any material change to our forecast.

Michael, this is Willie. You've probably seen the Permian numbers. We ended at 5.65 million barrels a day at the beginning of the year. We think we're right around 5.9 million barrels a day now, and our exit is kind of 6.15 million barrels a day. So we're kind of on track with what we had outlined in February.

Okay. Great. And then I realize you're not giving '24 guidance yet, but just wanted to ask in general, directionally, how we should think about '24 CapEx? Is there anything on the horizon that would point to that really being materially higher than 2023? Or do you think that could trend higher or lower?

Michael, we've kind of stated our expectations of between $300 million to $400 million of expansion CapEx, and we'll likely get the question. But as we think about our NGL assets up in Canada and what we're trying to do there, even if we move forward with that, I think we'll still be in that range on an annual average basis over maybe a couple of years. But most importantly, I don't think that we would be taking on any expansion CapEx that would jeopardize our free cash flow story and our desire to return capital back to unitholders.

Our next question comes from Spiro Dounis with Citi.

First question, just hoping you guys could update us on Corpus bound pipeline utilization. It seems like that's been getting kind of close to full. I was just wondering if the economics there at some point maybe start supporting the use of PRA again or maybe you stuck to these flows kind of turn back to Houston from here?

Well, I'll start with this, Spiro. The volumes on the long-haul lines down at Corpus are running very full. And we constantly optimize power and DRA to have the most economic way of delivering it. But Jeremy, do you want to comment a little bit on the outlook?

Sure. As we discussed, volumes are growing every month, and longer haul lines are getting more full. The Wink to Webster ramped up in February, as everyone is aware, a lot of that volume came off of inbound Houston pipes, which might have had some marginal impact on the Corpus pipes, but notably had an impact on spreads between Midland and the Gulf Coast. We expect volume growth to get us out of that and get it to more reasonable ranges and longer-term ranges where we've been contracting. So what I would say is that we continue to expect that to continue to happen. Corpus is the most logistically sound price, the shortest distance. It's nothing but Permian crude leaving the docks; it's an area that just will draw the incremental demand of our basin pipeline as summer driving season pulls up. We'll pull additional demand. So we're seeing more and more activity on the long-haul pipe as production has grown. As Willie mentioned, you get to 6.15 million barrels a day towards the end of the year, and they will be full. But you'll have balancing across the pipeline because all of the markets are needed, but Corpus will remain full since the marginal demand is an export barrel.

And Spiro, you probably already realized this, but we've contracted the majority of our long-haul space down to Corpus Christi for '23 into '24. And so back to our thesis of tightening capacity and margins in the out years, this is very supportive for that as we go forward for the next number of years.

Got it. That's helpful color. Second one, just going back to NGL in Canada. You guys have kind of talked about this debottlenecking and optimization for a bit now. Just curious, what are some of the gating items to kind of moving forward there? When do you think we can get closer to an announcement?

We expect to be able to give you an update in August on our August call. As you can imagine, putting these things together is a complicated situation, especially when you're trying to evaluate opportunities around debottlenecking and expansions and trying to link up commercial contracts to anchor it. So there's quite a bit of work that's been going on, and I think we'll be able to give you a good update in August.

Our next question comes from Brian Reynolds with UBS.

Maybe just a follow-up on the NGL segment. Your updated views from the guidance was expectations for being down roughly $100 million year-over-year. Just given the strong Q and really strong frac spreads to start the year and continuing throughout 2Q. Just wondering if there's any updated view there or if there's any maintenance in 2Q or beyond that we should be thinking about?

Yes, this is Al. I'll take a shot. We came into the year fairly hedged. As we commented, a little over 80% hedged. We had a strong 1Q. But our view is it really doesn't change the year. We're still guiding to $420 million for the full year, which again, in our prepared comments, we talked about probably a bigger saddle in the summer months. But what you're seeing there a bit too is we do anticipate a turnaround in the second quarter impacting some volumes as well as a market structure that incents us to store and sell next winter, some of which would push into the first quarter of 2024. So in summary, we didn't change our guidance for the NGL segment.

Just a couple of things to add, Brian. We had an asset sale in February. So the full year impact of that would reflect both. But a larger component is commodity-exposed barrels will be lower this year. There is a turnaround of the third-party facility that we received commodity-exposed barrels from. And there was a storm in the Williston last spring that led to additional volume and additional at the highest commodity exposed period. So I think the combination of those is probably a bigger driver for the year-over-year reduction in EBITDA.

Great. Really appreciate the incremental color. Next question is just on capital allocation. Plains is trending towards that 3.5 leverage target or below by year-end. And while distribution growth seems to be on the table for '24, I was kind of curious if Plains could provide updated thoughts and views around potential debt reduction, just S&P has recently kind of updated its views that it may not necessarily penalize equity credit for companies that have dramatically reduced leverage and look to reduce their cost of capital?

Yes. This is Al. I'll take a shot. The S&P kind of clarification of how they look at it is very favorable for potential reduction when and if it makes sense for us to. We value our financial flexibility in bringing our leverage down at least in the near term more than trying to take out any of the debt. So no change in our view, call it, in the near term or for the balance of this year, expect us to kind of revisit that maybe in the future. We do not view that the cost of the debt is so high that we should immediately sacrifice the balance sheet or financial flexibility to take them out. The weighted cost of the debt securities are below what we think our cost of capital is on a weighted basis. And this isn't the best debt market to go refinance in as well. So no really change in our thinking there. We're pleased because we do think we would meet the kind of the S&P exception of significantly lower leverage than when we last issued the debt securities. So we do think we've got incremental flexibility in the future, but definitely not this year.

Our next question comes from Jean Salisbury with Bernstein.

I just wanted to follow up on an earlier question. Your Corpus pipelines, I think, are at full capacity now with no real expansion capacity with DRA. Is that accurate? I know some of the other pipelines have been talking about potential expansions that I didn't actually think were possible, but wanted to see for claims if that was a possibility.

This is Jeremy. We don't foresee any expansions of our facilities at this time, the Cat 1 and Cat 2 assets.

Great. And then I wanted to also ask about your expectations of what duration is expected in recontracting if you were to kind of start blending and extending on your crude pipes in the next year or 2. We've heard from others that E&Ps are kind of really on the market for 3 to 5 years for recontracting as those contracts are coming up, but your high corporate utilization might better position Plains than others. So I wanted to get your thoughts there.

Jean, we're in the middle of those discussions and have been for a while. And it all depends on rates; at lower rates, we'd rather not have longer duration. We push for longer duration at higher rates. So I think that's something between us and our customers. But what I can tell you is we haven't seen any issues getting 5-year terms on contracts that we like and customers like. So I'd say we push towards the high end of that range.

Jean, this is Willie. I want to mention that our assets are part of an integrated base. When Jeremy's team considers recontract extensions, it involves not just the long haul but also the integration of gathering through the intra-basin alongside long haul. We believe this provides a broader opportunity for those looking to transport barrels.

That's helpful. And if I can sneak in one more really quick one. If that's the case, do you anticipate that the recent Energy Transfer acquisition of Lotus will have any material impact on Plains' businesses?

We don't. We've got a great system that you've heard a lot about, and we think it gives us all the flexibility we need.

Our next question comes from Neel Mitra with Bank of America.

This is actually Neel Mitra. First, I just wanted to ask regarding the NGL business. I know frac spreads have been really strong for the last kind of 1.5 years, but have you considered moving more to a fixed fee business just to create a little bit more stability longer term?

No. These assets that we're talking about are straddles; we have not looked to do that and don't anticipate that.

Got it. And maybe the second question for Jeremy. As you look at recontracting in '25 and '26, Corpus is getting a premium, but some of your producers looking at possibly having spot in place in Houston and that impacting the flows that would go to Corpus and the premium that you get...

So Neel, it's hard to speculate what would happen. The enterprise note is that demand for that probably is until 2027. So we're not sure what those markets look like. But what I can say is if that were to happen in 2027, that's because there's another 1.5 million or 2 million barrels a day of production, and Corpus flows wouldn't be materially impacted, and you need the same amount of barrels to clear because incremental demand is there. So the reason for it being pushed is largely because Jean mentioned lower contract duration. You need long-term contracts to get their docks, which are 40% to 50% utilized. Everything is moving and quality is maintained. We struggle to see it in the near term; we do agree with enterprise if there's a longer-term need and higher production. That means our gathering pipes are full, our long-haul pipes are full, and Corpus flows won't be materially impacted because that incremental volume will likely come from the inland docks and growth.

Great. And if I could just clarify one question on the gathering and intrabasin side. If the Permian continues to grow like you expect, at what point would you have to see kind of major expansions on your gathering and intrabasin system? And would that put you kind of outside of the $300 million to $400 million range at some point?

What was that range, Neel? I'm sorry; I just want to make sure I answered your question.

Just the CapEx range that you're in right now?

I don't foresee anything that would push us out of that range. I think the way I would look at it, Neel, is we're constantly debottlenecking and creating capacity. We announced earlier this year that there's probably $100 million of our capital program to create more capacity through stations and pipes. We can always ship on other pipelines if it's a temporal need for additional capacity. The Wink to Webster segment between Wink and Midland will come on towards the end of this year. But large segments of pipe in the neighborhood of $100 million to debottleneck the system; it's not hundreds of millions. And we'll have lots of gathering capacity in and out. So the shorter answer is we don't see much that would push us out of that potential acquisitions and other things that we might look at from time to time. But as far as building organic projects, we don't see a ton of need for multi-hundreds of millions of dollar projects.

Yes. This is Willie. If you look at Slide 5, there's a good illustration of our operating leverage in the Permian. And as Jeremy said, we're constantly trying to optimize the system to be able to get more out of it. So I think it will be a number of years before we hit constraints, meaningful constraints.

Our next question comes from Jeremy Tonet with JPMorgan.

This is Vrathan Reddy on for Jeremy. Just curious, looking past 2023, how you guys think about risk to long haul versus intrabasin and risk gathering volumes and when you guys might see capacity becoming tighter.

We're consistently working to manage the volume with producers on the gathering side. Our goal is to stay ahead of these producers by implementing an active program to address any constraints. Depending on how volume flows are directed, there may be intra-basin constraints, but we collaborate with our partners to resolve these issues. This is where investments are being planned as mentioned by Neel. If demand increases towards Houston or Corpus, we may need to expand our capacity in a specific area. While there may be some temporary intra-basin constraints, we have strategies in place to address them, and we are making the necessary investments. On the long-haul side, the situation varies by market. For instance, Corpus is currently over 90 percent utilized, but there are still multiple routes for the barrels, including flows to Houston and Nederland. Over time, the differentials are aligned with the potential for incremental investment and expansion. However, we would likely need to see a rise in rates before considering further expansion, which is probably a couple of years away.

Maybe just as a reminder, as you think about long haul, there's about 8 million barrels a day of total capacity takeaway capacity out of the basin. If you look at economic capacity, it's roughly a little bit over 7%. Our forecast for year-end, as we talked about, was just a bit over 6%. So you can see the capacity there. And as you start filling that up and you use Drag Reducer to try to get into the higher end of the volumes, the costs go up. And so that's part of the reason that we think that margins ultimately have to get stronger as we go forward.

Great. And then on the energy transition front, kind of switching gears. Just wondering what kind of capital, I guess, would be deployed by this group? What are the types of projects the team is focusing on? Or any incremental updates there?

Sure. This is Chris Chandler. We continue to evaluate a number of projects in this area. The one we've announced is a battery energy storage project at our Sarnia, Ontario facility. That's actually in construction and will begin operation this summer. It's a modest investment, less than $10 million. We're looking at a number of different areas, whether that's renewable power generation behind the meter at our existing facilities, converting existing assets or pipelines, and looking into projects like Hydrogen storage underground. In particular, our Canada storage position lends itself to opportunities to store hydrogen. So we're looking across the partnership. But at the end of the day, these projects have to compete for capital and have to meet our investment hurdles.

Our next question comes from Gabriel Moreen with Mizuho.

Could you provide an update on the Capline volumes and the performance of that asset? Additionally, assuming the Trans Mountain Expansion begins operating early next year, how well protected are your crude oil pipelines coming out of Canada in relation to that startup?

Sure. So on the Capline front, we've seen quite a bit of demand from the existing shippers and the same games refiners. So based on incentive volumes and committed volumes, that's been outperforming year-to-date, and we expect that to continue—a mix of light and heavy barrels. And then on the TMX startup, the way to think about that is you've got heavy crude that will leave and head west when it does start up that could impact some heavy crudes going to the east and into the United States, but they need barrels to run, right? They're largely not getting exported out of the Gulf Coast. So that could bring either additional imports or it could bring additional barrels to the Mid-Continent refining complex that folks wind that up. So that could support our basin pipeline and our Mid-Continent. So it could draw additional barrels into the Cushing area, that could be a positive. Capline, I think, will continue to move because those movements are for specific refiners who are looking for and they could have some imports, but largely, we would expect quite a bit of those barrels to move. Our Canadian assets are largely insulated. Those are largely gathering assets into the mainline. So if the differentials would tighten, that would increase the realized price and incent more production and volume to come. So we think it would just be a matter of time before things normalize because with additional takeaway and lower differentials, we might see lower market-based opportunities, but we could see some more fee-based opportunities and volume growth among the systems.

Our next question comes from Neal Dingmann with Truist.

This is Jake Nivasch on for Neal. I just wanted to go back to the customer contracts. I know you mentioned the duration the color that you provided there. But I just wanted to get a sense. Can you remind us, I guess, what time of year typically do these customer contracts get reevaluated? And I guess, could you provide, if possible, a quantification of, I guess what percent of those contracts are up for renewal?

Thanks for your time, Jake. It's a fluid situation because each contract has specific notification periods for cancellations or options. Therefore, we cannot pinpoint exact timings, as much of it depends on the annual timeline for when the pipeline is operational. Unlike NGL sales or purchases, there isn’t a designated contracting season. However, we've successfully recontracted many producers for extended terms, significantly longer than their long-haul agreements on our gathering systems. The key factor moving forward will be the price when we reach the long-haul phase. We maintain open communication, and decisions are based on the price aligning with what we view as appropriate. We are optimistic about the pipeline volumes and anticipate that we will continue to recontract, which will support utilization. I don't believe I have anything further to add at this moment.

Sure. And just a quick follow-up here. I know you guys mentioned hedges in 2023, I guess, about 80%. But do you have any update on '24 hedges? Have you guys added anything recently there?

I assume you're talking about natural gas liquids; the answer is we haven't given any guidance on 2024.

Our next question comes from Sunil Sibal with Seaport Global.

So I was curious, it seems like upstream M&A, especially in Permian, has picked up pace. I was curious how this impacts Plains, especially with regard to your negotiations on recontracting? And more broadly, the integrated model that Plains has had so much success with in Permian?

Sunil. I'll take it in a couple of steps. M&A has been happening for a long time in the Permian. And the bigger the customer, the larger they become, the more they're largely driven to us in an integrated nature and more options. So that's a positive; as they get bigger, they do push more on rates, but we try to add services and balance a lot of that off. We have some unique attributes to the system, which gives us a premium relative to other services, and we lead into that. But by and large, everyone is happy in the end. I would put it that way. The other thing about M&A is the way it's been run lately is producers are buying inventory and largely financing with selling lower-tier inventory. The benefit of that is that lower-tier inventory that wasn't going to get drilled could be dedicated to our system—private equity comes in, buys it, and immediately starts to drill it, which has been supporting the growth numbers we've seen. So while it is, on the surface, reducing rigs, their private equity adding rigs, that's why you see stability in the rig count. So some of it is a positive for us as we see incremental production in places where we weren't seeing it before.

Got it. And then when I look at your commodity price assumptions, it seems to me that the Canadian AECO price assumption of CAD 350 per gigajoule is probably one of the biggest variables. Is that thinking correct? And if so, any sensitivity on that price to your NGL segment?

Sunil, we've got a pretty good sensitivity on that we disclosed on one of the slides. What I would tell you, you've got AECO, there's a lot of pieces that fit into that. You've got AECO; you've got the price of the NGL barrels, and then you've got some basis differential between Mont Belvieu and the markets we serve. So I would just go back to the rule of thumb that we have, which is on an annual basis, a $0.01 worth of about $7 million of frac spread. On a clean year, right.

I'm not showing any further questions at this time. I'd like to turn the call back over to the company for any closing remarks.

Well, listen, thanks to all of you for joining us today. Hopefully, the new time works a little bit better for folks. We look forward to seeing you soon. Have a great day.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.