Plains All American Pipeline LP Q1 FY2021 Earnings Call

Good day and thank you for standing by. Welcome to the Plains All American's first quarter 2021 earnings call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. I would now like to hand the conference over to your speaker today, Roy Lamoreaux. Please go ahead. Thank you, Joseph. Good afternoon and welcome to Plains All American's first quarter 2021 earnings call. Today's slide presentation is posted on the Investor Relations website under the News and Events section at plainsallamerican.com, where audio replay will also be available following today's call.

Thanks, Roy, and thanks to each of you for joining us this evening. We plan to keep our prepared comments brief. We continue to make solid progress on our plans, reporting first quarter results that exceeded our implied expectations by roughly $50 million, generating strong free cash flow, maintaining full year 2021 adjusted EBITDA guidance at plus or minus $2.15 billion, and advancing a number of key objectives. I'll note that our full year guidance incorporates an estimated $25 million net benefit from winter storm Uri. Al will provide more detail on our results and outlook in this section of the call. I'll plan to focus my comments today on our longer-term positioning. We are increasingly constructive in our outlook for global energy demand recovery. COVID vaccinations are progressing. Key world economies are reopening, and global inventory levels have drawn down meaningfully. On the supply side, the combination of OPEC's discipline, recent increases in Permian activity levels, and our ongoing dialogue with producers reinforces our confidence in the Permian to resume growth in the back half of 2021. And importantly, building momentum into 2022 and beyond as global supply and demand balance improves. We expect the Permian to exit 2021 at 4.4 million to 4.5 million barrels a day, which is an increase of 200,000 to 300,000 barrels a day from year-end 2020 to year-end 2021. Notwithstanding our constructive bias, we chose to maintain our 2021 adjusted EBITDA guidance of $2.15 billion at this time due to the combination of the timing matters that Al will cover and the fact that our constructive view of the fundamentals is weighted toward the end of the year. For PAA, we believe 2021 represents a meaningful cash flow injection point.

Thanks, Willie. As shown on slide six, our first quarter fee-based adjusted EBITDA of $559 million exceeded expectations and was in line with fourth quarter 2020. First quarter results benefited from lower power costs, including gains on power hedges, and stronger results in our natural gas storage business, as well as some lower operating expenses that are timing-related, and we expect to incur later in the year. These benefits more than offset the revenue impacts of the storm-related downtime across our Texas and Mid-Con pipeline systems as well as lower realized revenue at certain non-hub crude terminals and Canadian NGL facilities.

Thank you, Al. We've turned a meaningful corner with respect to free cash flow generation, and we expect to enhance unit holder value by generating significant levels of free cash flow over a multiyear period, and we will continue to allocate free cash flow to the benefit of our unit holders. We are increasingly constructive on the long-term outlook of North American energy, including our business as global demand continues to recover. Meanwhile, our focus continues to be maximizing our free cash flow through optimizing and rationalizing our systems, working with customers, partners, and peers to align interests, streamline and rationalize excess capacity, lowering our cost of operations, advancing our sustainability program, and above all, delivering safe, reliable, and responsible operations. A recap of our 2021 goals are outlined on slide 10, followed by a summary key takeaways from today's call provided on slide 11. We appreciate your investment in and support of Plains, and we look forward to providing you with additional updates on our continued progress. With that, I'll turn the call over to Roy to lead us into Q&A.

Thanks, Willie. We enter the Q&A session. Please limit yourself to one question and one follow-up question and return to the queue if you have additional follow-ups. This will allow us to address the top questions for as many participants as practical and are available time this afternoon. Additionally, our Investor Relations team plans to be available throughout the week to address additional questions. Joseph, we're now ready to open the call for questions.

Thank you, presenters. We have our first question from Shneur Gershuni. Your line is open.

Hi. Good afternoon, everyone. Maybe to start off, I was wondering if you can sort of reconcile the guidance for me a little bit here. Overall, you had a strong quarter, certainly better than you had guided from a fee-based perspective. Your commentary on the call today is definitely more constructive than it was last time. You talked about building momentum. It sounds like your production forecast for the Permian, back-half weighted, but it's certainly better. And so, kind of on the math, you kind of view expectations by $60 million, that your fee-based guidance is only up about $25 million. Is that in the election of conservatism? I think you had mentioned the word election before? Or is there a degradation in the base business? Is something happening in the back half of the year? I was wondering if you can just sort of expand on that for us, if you can.

Thanks, Shneur. I'll begin, and then I'll let Jeremy and Harry provide additional details. Are you asking about the full year or just the first quarter?

It's around the full year. I mean, at the end of the day, you beat expectations, but you maintain guidance, which it seems to even on the fee-based basis, seems to imply that you're expecting a worse back half of the year. But you talked about momentum and positive commentary. So I was just trying to figure out if you can square that if that's conservatism or if there's something that we need to be thinking about?

Yes, let me start, and then others can join in. In my prepared remarks, I mentioned that the benefits of the storm amount to $25 million for the year. This is related to some of the impacts of the storm being shifted into S&L, and I think that will be a good starting point for Jeremy to provide more insight.

Good afternoon, Shneur. We've experienced a bit of an acceleration. In the first quarter, the $50 million you mentioned primarily came from the transportation segment, which benefited from lower operating costs, although this was somewhat offset by reduced volumes. Our Facility segment also gained from some opportunistic activities related to our NGL facilities. We did defer some operating expenses of about $5 million to $10 million to later in the year due to timing and interruptions in Q1, contributing to the net reduction from $50 million to $25 million. Another factor is related to S&L, where some effects from storm Uri have pushed into the second quarter and beyond, influenced by market spreads and timings. The erosion observed is tied to the variability associated with Uri. Therefore, looking at the net impact of $25 million compared to $50 million, the remaining potential is still uncertain. While we’re seeing completions and efficiencies, the pace of rig acceleration hasn’t increased. We anticipate production growth to be back-end weighted. Additionally, we’re not observing Canadian differentials widening to historical levels due to proration rates, which is accounted for in our plan. Overall, our core Permian and other assets are performing as expected, with no decline in that core business.

Okay. That makes sense. Really do appreciate the wait and see aspect of it. Maybe it's a follow-up question. I was wondering if we can talk about the asset sale process. If you can remind us in terms of the timing and EBITDA that you've baked into the guidance for this year? And does this process block you out from doing any share repurchases?

So, this is Jeremy Goebel again. As Alan, Willie both stated, we are very confident in our ability to execute. The processes all began in the first quarter of this year. We don't want to speculate on timing or impact of the transactions just for the sake of confidentiality. But I feel very strongly in our ability to execute with regard to our targets.

Richard, why don't you comment on the blackout period?

I believe the asset sales won't affect the timing. Regarding share repurchases, we included that in our guidance, so it won't impact our ability to conduct repurchases.

Okay. Perfect. Thank you very much. Really appreciate the color and the clarification today.

Thanks, Shneur.

We have our next question from Christine Cho from Barclays. Your line is open.

Thank you. Yes, Jeremy, you usually provide sort of like expectations for what exit rate for the year is on Permian volumes. So curious, if we could kind of get that and maybe sort of what that means for 2022, for you guys? And in that context, how should we think about earnings growth tied to the volumes with the headwind that we're going to be one year closer to some contract expirations. Just at what point do you guys think about blend and extent to keep the volumes on your system for longer?

Jeremy?

Christine, good questions. So we'll start. And if I get them right, I heard there's an exit rate. What does that mean for momentum into 2022? And then what does that mean for our ability to contract longer-term on our pipes.

Right.

In response to the first question, we are observing a positive trend in drilling and rig completion efficiency, which is evident in shorter cycle times and improved estimated ultimate recoveries, mainly due to spacing. February presented some challenges as Texas and New Mexico production dipped, but March and April showed a stronger recovery. We are witnessing a boost in some completions in the current commodity environment; however, the rigs are not sufficiently available to meet our initial projections. While production is accelerating, it hasn't significantly altered our outlook. We estimate starting the year at 4.2 million barrels per day and anticipate ending at between 4.4 million and 4.5 million barrels per day. Rigs are essential for this acceleration. Regarding our 2022 expectations, we are cautiously optimistic about North American production, but it ultimately hinges on supply and demand dynamics. A significant ramp-up in rig availability is unlikely until OPEC production is adjusted and demand increases correspondingly. It’s too early to make definitive predictions for 2022, as we require additional rigs to achieve substantial production growth. I realize I didn’t provide a direct answer to your question, but that's our current perspective. Concerning blend and extends, we maintain ongoing discussions with our customers. With the current differentials, it complicates re-contracting at acceptable levels. We are focused on keeping close connections with our customers and have dedicated over 2.5 million acres with terms that are extending. Our customers are satisfied, and when they need to re-contract, the primary issue with long-haul pipes is securing supply. We are in a strong position having purchased over 900,000 barrels per day, allowing us to either fill our pipes or negotiate contracts effectively. Volume won’t be an issue in filling our infrastructure; timing is key. We believe we have advantages that many do not, and we are willing to wait for the right opportunities. The industry understands the overcapacity, and there are ongoing discussions about options to rationalize, and we intend to be integral to those conversations.

And Christine, I'm sorry, go ahead.

No, go ahead, please.

I wanted to mention that the key point is the momentum that we anticipate building towards the end of 2021. It's crucial to establish this momentum, as without it, there will be a longer delay before we observe any benefits. We remain optimistic and believe that the recovery will drive a faster growth trajectory into this year, assuming everything proceeds as we expect.

Okay. And then, just because you did sort of end the comments on pipeline or rationalization. As we think about that, it would seem that a conversion to gas would maybe make the most sense since we have sufficient takeaway on the NGL side. From what I understand, it doesn't sound like it's simple to convert a liquids pipe to gas? It sounds like it requires meaningful CapEx to change out pump stations. And I've also heard that the diameter needs to be at least 30 inches. Is that right or are there other things that these pipes could transport that would require less spending? Just trying to get a sense of what the options are here?

Well, Jeremy and Chris have been working on this. Jeremy, why don't you start off?

Christine, thank you. Regarding the rationalization aspect, gas is a suitable option for takeaway as we expect more gas to enter the market. The focus here is on valuation, capital, and scope, which we review periodically. Additionally, we must consider how to handle existing contracts and current pipeline structures. This is just one of several options we are exploring, and so are our peers. I encourage you to be patient as we don’t have specific details at the moment. Some of your observations about gas are accurate; the compressible nature of gas and the increased fuel consumption with smaller diameter pipes do hold true. We are examining all these factors, but I ask for your patience as the industry works through the best solutions, as we are all committed to this effort.

Chris, do you have anything you want to add?

Yes, this is Chris Chandler. I would like to confirm the points made in your initial question. Natural gas pipes are typically larger and require compression instead of pumps like those used in liquid pipes. This can certainly be done and is specific to the asset in question, and it has been done multiple times, including instances of switching between liquid and gas. There are opportunities to pursue this, but generally, you must replace pumps with compressors, and using a smaller pipe than what would be installed if building from scratch can affect efficiency or capacity.

And Christine, this is Willie. One of the other benefits, I think, that's important is it seems as if it's getting harder and harder to build assets now. One of the things that we've got is a lot of operating leverage in our system, which gives us the capability to be able to evaluate some of these things, perhaps more than others. And the challenge really is, if you think about capital efficiency across the industry, while it may not be perfect and if you're designing it from scratch, you'd go with a new line of a certain size. In many cases, when you factor all these other things in, it does make a lot of sense. And that's what the industry really needs to start working through. So really helpful. And maybe if I could just tack on a follow-on. Are all your major long-haul pipes out of the Permian over 30 inches or more?

This is Chris Chandler. They vary in size from 20, up to 36 inches.

Great. Thank you. That’s it for me.

Thanks, Christine.

We have our next question from Jeremy Tonet from JPMorgan. Your line is open.

Hi, good afternoon.

Hi, Jeremy.

Can you elaborate on your discussions with producers and what gives you confidence for 2020? It seems that private companies are being more active compared to public ones. How do you perceive this, and what different activity trends are you noticing that could impact Plains?

Jeremy?

Thank you for the question, Jeremy. The situation is consistent. Public companies are primarily focused on maximizing free cash flow while waiting for supply and demand to stabilize, as their investors require it. This means more free cash flow is being returned to shareholders and used to reduce leverage. In contrast, larger private producers with minimal or no debt are recognizing the returns and are investing significantly. It's not simply a matter of private versus public; rather, there are a select few large private companies that are well-capitalized and aggressively pursuing growth. While they'll influence the market, they aren't the sole factor at play. With oil prices around $65 and slight backwardation instead of a steep backwardation, producers have the opportunity to hedge, which leads to increased free cash flow for them to manage. Overall, market conditions reflect flat pricing, but there's cautious optimism in the sector. Some specific operators are taking proactive steps, and while generalizations are often made regarding private and public companies, there's a complex interaction at work, with certain entities actively pushing forward.

Got it. That's helpful. Thank you for that. And just want to pivot towards energy transition, obviously, very topical and getting more topical. I'm wondering if you had any thoughts on that subject these days. And specifically, thinking about carbon capture and wondering if you see the 45Q credit as the written right now is kind of sufficient to move forward with projects. If you have existing assets that could be kind of redeployed in that direction. Just any thoughts in general would be helpful.

Jeremy, this is Willie. Regarding CO2 sequestration, we haven't been very active in evaluating transport options. Others might comment on it as well. It’s important to note that our company does not produce resources or manufacture products. We have agreements to facilitate the movement of products and to find solutions. While there hasn't been much progress on specific sequestration projects, we remain closely engaged with our upstream and downstream peers. There is significant activity in the sector, and our role is to explore how we can create solutions for transportation. Currently, we haven’t made any advancements in CO2 initiatives, and I don’t have any updates to share, but we continue to stay informed about potential opportunities in energy transition.

Got it. I'll leave it there.

Thank you.

We have our next question from Tristan Richardson from Truist Securities. Your line is open.

Hi, afternoon, guys. Clarification question with respect to the upper bound of potential repurchases. Should we think of that as inclusive of asset sales to the extent they materialize throughout the year? Or is that purely just of the free cash flow after distributions guidance?

Al, why don't you take that?

Yes, I would consider the up to 25% as the maximum, but we have specified that when it comes to asset sales, we will take into account and consider the EBITDA from those sales as well. Therefore, when selling an asset, a portion of the proceeds will need to be allocated to reduce debt in order to maintain flat leverage. This should be taken into consideration. We provided the up to 25% figure as a theoretical maximum, but in practice, it will be lower with asset sales. Additionally, I would direct you to other factors mentioned on our slide nine, as there are various considerations that will influence this. We see this as an instrument that will play a role in our capital allocation moving forward, but several factors will be at play.

That's helpful. And then I appreciate the earlier comments on the cadence of the year. Curious if there is any delta around the timing of asset sales that's factored in? Just to follow-up on a previous question, sort of has the timing changed within the year in terms of general assumptions for asset sales that are contributing to that fourth-quarter weighted outlook?

Tristan, it's Jeremy. I'd say, one, we don't want to speak to timing of the asset sales, as we talked about earlier. But we have assumptions in there. They haven't materially changed since the beginning of the year. If something does change, we'll update once we make the announcement of the divestiture.

Appreciate. Thank you guys very much.

Thank you, Tristan.

We have our next question from Keith Stanley from Wolfe Research. Your line is open.

Thanks. Good evening. Just two quick follow-ups. First, sorry if I missed this. Did you comment on the amount of asset sales completed now year-to-date?

Keith, this is Jeremy Goebel. We've completed $20 million of asset sales to date. And so that's consistent with what we had. I guess we did that in January of this year. So that's the total amount completed to date, the rest is in progress.

Okay, great. And then the other one, I just want to understand. So, the lower NGL intersegment fees item. I assume that's just you're lowering rates on some of the facilities assets that the S&L business uses. And I just want to clarify, I think you said facilities EBITDA is hurt $40 million by this, and it helps S&L by $40 million for the year.

Keith, that's correct. This is Jeremy. Effectively thinking about it is we just charge our marketing affiliate market rates, and we look at that, we make assumptions for the beginning of the year, impacted by market structure and competitive rates around the area. And so we've made that adjustment. And so it's a net neutral. It's just an allocation from facilities.

Great. Thank you.

We have our next question from Gabe Moreen from Mizuho. Your line is open.

Hey good afternoon everyone. Most of my questions have been asked or answered, but maybe I was just going to talk about how, I guess, low you think you can sort of whittle down your ongoing maintenance CapEx and just out CapEx outside of where you're kind of finding those savings so far and how you might be able to take those numbers on an annual basis?

Sure, Gabe. I'll let Chris Chandler address that.

Hey Gabe, it's Chris Chandler. I'll start with maintenance capital. We've said previously that we think a long-term run rate for maintenance capital is less than or equal to $200 million. We still believe that to be the case. We did update our guidance for 2021 to $180 million, a $15 million reduction. There's a number of factors driving that, including asset sales that have been completed and ones that are forecasted later in the year. We're also completing a number of multiyear improvement programs related to integrity and reliability that we won't have to spend on going forward. Regulatory requirements continue to evolve as do best practices around the inspection methodology tools and analysis. So it’s a number of factors that by all means not a lack of investment or lack of commitment to maintenance or integrity. But when best practices are found internally or within the industry, we certainly look to apply those. As to your question on investment capital, we've lowered our guidance there by $50 million from $425 million to $375 million. Likewise, there's a number of factors involved. We're always looking to optimize our maintenance capital spend. So some of that's cost improvements, scope reductions, timing optimization we'll talk with our customers and if we can delay a part of the scope of a particular project without a financial impact or with support of the customer we will do that. We've also pushed back the start of construction for the Byhalia project. That's the piece of the Diamond expansion at the very end the 40 miles that goes from the Memphis refinery to the cap line facility outside by in Mississippi. We've done that to take some time to evaluate some alternatives in response to our stakeholder engagement activities that we've been doing for almost two years now. We're still planning on a start-up by year-end. But if the alternatives cause that to change, we'll certainly provide an update when appropriate.

Hey Gabe, this is Willie. One thing I want you to take away from what Chris talked about is back to the maximizing free cash flow goal that we all do. I mean, it's part of our dialogue every day as we think about investment CapEx, maintenance CapEx, operating costs on how do we maximize free cash flow, right? And so it is a much broader discussion, and it's really taking hold in the business, and that's why we think we will continue to have success in that area.

Thanks. Maybe I could just ask a quick follow-up on, I guess, the Byhalia extension. If your time-line slips there for whatever reason, because you have to look at alternatives, do the Capline contracts still kick in as expected or are those tied together somehow?

So this is Chris. I'll answer that. On the Capline reversal, the mainline that originates in Patoka and into St. James, that project is moving ahead as scheduled. It is an independent project, and it's independent of anything on the Diamond expansion and the Diamond extension. So things are unchanged there, and that's still on schedule for a startup by year-end.

Thanks, Chris.

We have our next question from Michael Lapides from Goldman Sachs. Your line is open.

Yes, thank you for taking my question. I wanted to follow up on Diamond Capline. Can you remind us when you expect Capline to be fully operational for both legs? And will it achieve full run rate EBITDA in the first year, or will it take a couple of years to ramp up to that?

Jeremy?

Thank you for the question. As Chris mentioned, we are evaluating some alternatives regarding the Diamond piece. To reiterate what Chris said, you will reach full run rate on committed capacity for Capline from north to south. There is some uncommitted space that we aim to fill, and based on current commitments, we expect to achieve full run rate in the first quarter of 2022 from the north to southeast, with additional commitments anticipated over time. Regarding the Diamond piece, we are assessing alternatives and will keep you updated as soon as possible.

Got it. And then on Diamond, it's gotten messy, obviously, if the city council and with the litigation underway as well, both state and federal. Just curious, is there an opportunity to use your partner’s pipeline? There’s a second pipeline that runs not too far from Byhalia. Do you have that opportunity to utilize that as they work around, or is that a full pipe right now?

Michael, this is Willie. I would tell you, we're evaluating all options and leave it at that.

Got it. Okay, thanks guys. Much appreciated.

Thank you.

We have our next question from Jean Ann Salisbury from Bernstein. Your line is open.

The committed tariff that was posted for Wink to Webster recently for $0.72 and then $0.45 per barrel, which I think has caused some investor confusion, and if we're being honest some confusion for me as well. Is the right way to think about it, that's just an interim rate for large customers and the true committed long-term rate hasn't been posted or disclosed yet?

Jean Ann, this is Jeremy. You're absolutely correct. This is just interim service with limited pump capacity. It's limited origination capacity, and it's effectively matching the AR from Midland to Houston during a period prior to the fourth quarter when the MBCs kick in. So that has no reflection on the long-term committed here and limited destination alternatives.

Okay. And eventually, when the pipeline is up and running that long-term tariff freight will be posted?

That’s correct.

Okay. Thank you. And then as a follow-up, any update on the Rangeland expansion? It seems like with Keystone getting axed that might be garnering more interest?

Jean Ann, this is Jeremy. We're in constant dialogue with our customers. We have interest in that expansion. But at this point, we're shipping and our capacity is full going south from Canada to the U.S. and multiple destinations.

Okay. Thanks.

Thanks, Jean Ann.

We have our last question from Harry Mateer from Barclays. Your line is open.

Hi, good afternoon, guys. Al, you highlighted the large drop in short-term debt in the first quarter. And I think historically, you've tended to guide for that number to sort of fluctuating in the $400 million to $800 million range. Is that still a good guide to use? And how should we think about the short-term debt line trending for the rest of 2021?

Yes. What we would say is, it's obviously, a number of variables that will impact kind of the long-term trend, but that's probably still a reasonable long-term number. What I would say is we do expect some of the benefit we saw in 1Q to be temporal. But we do expect, again, on our free cash flow after distributions to be in that $400 million number. Clearly, 1Q was $500 million. So that kind of tells you what we expect some of that benefit we've seen in 1Q to be temporal.

Okay. Thanks. And then related to that, just when it comes to debt reduction, you think about getting these asset sale proceeds in the door, how are you planning to prioritize that debt reduction? Is there something pre-payable you have? Or is it going to be about lengthening runway? Or might you target some high coupon debt to sort of better boost metrics like free cash flow and coverage?

Most of our high coupon debt has a lot of maturity left to it. So it's obviously harder to get out and take out, and there's an upfront cost associated with that. We do have, I think, $1.15 billion maturing within the next couple of years. And a few other issues shortly after. So we will likely target some of the near-term senior note maturities to look to retire some on the front end. With that said, we will take a look at if there is an economic benefit to some of the longer-dated stuff, but it's out there a ways. And we think we'd be better suited to try to maintain and manage near-term exposure.

Okay. Got it. Thanks very much.

Thanks, Harry.

I wanted to thank everybody again for joining our call, and we look forward to having follow-up conversations with many of you in the coming days. So thanks again, and we look forward to updating you again in August.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.