Good day, and thank you for standing by. Welcome to the PAA and PAGP Q1 2023 earnings conference call. At this time, all participants are on a listen-only mode. After the speaker's presentation, there'll be a question-and-answer session. To ask a question during the session, you'll need to press star one on your telephone. You will then hear an automated message advising your hand is raised.
To withdraw your question, please press star one again. Please be advised today's conference is being recorded. I would now like to turn the conference over to your speaker today, Blake Fernandez, Vice President, Investor Relations. Please begin.
Thank you, Kevin. Good morning, and welcome to Plains All American's Q1 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 relation 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 two. Highlights from the quarter are provided on slide three.
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, thank you for joining us. Earlier this morning, we announced strong results reflecting good progress towards executing on our full year 2023 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, as illustrated on slide four, our focus is on execution.
Through the Q1, we've done just that, reporting Adjusted EBITDA attributable to PAA of $715 million. As a result of our Q1 performance and our outlook for the balance of the year, we are reaffirming our Adjusted EBITDA guidance range of $2.45 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 in 2023 outlook in his portion of the call. Let me shift to the Permian. We continue to capture increasing volumes on our system. We expect production growth of ±500,000 barrels a day exit to exit in 2023, based on an assumed 2022 exit production of approximately 5.65 MMbpd .
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. 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 five, we expect year-over-year growth in our crude oil segment underpinned by continued Permian production and tariff growth volumes in our gathering and 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. With that, I'll turn the call over to Al.
Thanks, Willie. We reported Q1 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 nine and 10 in today's appendix contains walks which provide more detail on our Q1 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 saddle versus 2022, which reflects lower volumes due to a planned third-party turnaround in the Q2, the February sale of our non-op interest in the Keyera Fort Saskatchewan facility, and an NGL market structure that supports increased sales volumes in the peak winter demand months relative to the summer months.
Regarding capital allocation, as illustrated on slide six and consistent with our February outlook, we remain committed to significant returns of capital to our equity holders, continued capital discipline. 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 3.5 x. 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 Saskatchewan opportunity. With that, I will turn the call back to Willie.
Thanks, Al. Today's results reflect another quarter of strong execution. 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. 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 unit holders through our targeted multiyear distribution growth.
A 8.5% current yield, significant free cash flow generation, balance sheet strength, as illustrated on slide seven. We appreciate your continued interest and support. 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. As we enter the Q&A session, please limit yourself to one question and one follow-up. For those with additional questions, please feel free to return to the queue. This will allow us to address questions from as many participants as practical in our available time this morning. Additionally, the IR team will be available to address any additional questions you may have. Kevin, we're now ready to open the call for questions.
Thank you. Ladies and gentlemen, if you have a question or a comment at this time, please press star one one on your telephone. If your question has been answered or you wish to move yourself from the queue, please press star one one again. We'll pause for a moment while we compile our Q&A roster. Our first question comes from Michael Blum with Wells Fargo. Your line is open.
Hey, thanks. Good morning, everyone. Wanting to talk about Permian growth. Curious if you're seeing any change in producer activity or messaging as commodity prices pull back, any updated outlook for Permian growth rate in 2023.
Jeremy?
Hey, Michael Blum. Good morning. What I would say is combination of activity, as Willie Chiang alluded to, of 340 rigs still working, that's in line with our plan and activity. Number of completion crews, number of connections in the first half of this year and the second half. Current volumes on the system, that growth implies roughly to 40,000 to 50,000 bpd per month of growth necessary to achieve the 500,000 bpd growth range. Discussions with producers.
We're in this 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. 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 at the beginning of the year. We think we're right around 5.9 now, and our exit is kind of 6.15. We're kind of on track with what we had outlined in February.
Okay, great. Thanks for that. Realize you're not giving 2024 guidance yet, but just wanted to ask in general directionally how we should think about 2024 CapEx. Is there anything on the horizon that would point to that really being materially higher than 2023? Do you think that could trend higher or lower? Thanks.
You know, Michael, we've kind of stated our expectations of between $300 to 400 million of expansion CapEx. We'll likely get the question as we think about our NGL assets up in Canada and what we are 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 number of years. 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 unit holders.
Thanks, Willie.
You bet. Thank you.
One moment for our next question. Our next question comes from Spiro Dounis with Citi. Your line is open.
Thanks, operator. Morning, everybody. First question, just hoping you guys could update us on Corpus-bound pipeline utilization. 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 DRA again, or maybe you start to see these flows kind of turn back to Houston from here?
Well, I'll start with this, Spero. The volumes on the long-haul lines down to Corpus are running very full. We constantly optimize power and DRA to have the most economic way of delivering it. Jeremy, you want to comment a little bit on 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's aware. A lot of that volume came off of inbound Houston pipes. Might have had some marginal impact to 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. What I would say is that we continue to expect that to continue to happen. Corpus is the most logistically sound place i t's the shortest distance. It's nothing but Permian crude leaving the docks. It's an area that just will draw the incremental demand. Our Basin Pipeline, as summer driving season pulls up, will pull additional demand.
We're seeing more and more activity on the long-haul pipes as production has grown, as Willie mentioned. You get to 6.15 MMbpd towards the end of the year, they will be full, but you'll have balancing across the pipelines because all of the markets are needed. Corpus will remain full since the marginal demand is an export barrel.
Spiro, you probably already realize this, but we've contracted the majority of our long-haul space down to Corpus Christi for 2023 into 2024. 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. Thank you both. The second one, just going back to NGL in Canada. You know, 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. 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.
Great. Good, good to know. That's all I have today. Thanks, guys.
Thank you.
One moment for our next question. Our next question comes from Brian Reynolds with UBS. Your line is open.
Hi, good morning, everyone. Maybe just to follow up on the NGL segment. You know, your updated views from the guidance was expectations for being down roughly $100 million year-over-year. You know, just given the strong quarter and really strong frac spreads to start the year and continuing throughout, Q2, just wondering if there's any updated view there or if there's any maintenance in Q2 or beyond that we should be thinking about. Thanks.
Yeah, this is Al. I'll take a shot. We came into the year fairly hedged, as we've commented, you know, a little over 80% hedged. We had a strong Q1, but our view is that 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.
What you're seeing there a bit too is we do anticipate a turnaround in the Q2 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 Q1 of 2024. 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. A larger component is commodity-exposed barrels will be lower this year t here is a turnaround at a third-party facility that we receive commodity-exposed barrels from. There was a storm in the Williston last spring that led to additional volume and additional at the highest commodity exposed period. 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. You know, Plains is trending towards that 3.5 leverage target or below by year-end. While, you know, distribution growth seems to be on the table for 2024, kind of was curious if Plains could provide updated thoughts and views around potential pref reduction just given, you know, S&P has recently kind of updated its views that it may not necessarily, you know, penalize equity credit for companies that have dramatically reduced leverage and, you know, look to reduce their cost of capital. Thanks.
Yeah, this is Al. I'll take a shot. Yeah, the S&P kind of clarification of how they look at it is very favorable for potential reduction, you know, when and if, you know, 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 pref. 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 pref are so high that we should, you know, immediately sacrifice the balance sheet or financial flexibility to take them out.
The weighted cost of the pref securities are below what we think our cost of capital is on a weighted basis. This isn't the best debt market to go refinance in as well. No really change in our thinking there. We are pleased because we do think we would meet the S&P exception of significantly lower leverage than when we last issued the pref security. We do think we got incremental flexibility in the future, but definitely not this year.
Great. Appreciate your updated thoughts. Have a good rest of your morning.
Thanks, Brian.
One moment for our next question. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.
Hi, good morning. Hi, 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 CRAs. 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 Plains if that was a possibility.
Jean Ann, this is Jeremy. We don't foresee any expansions of our facilities at this time, the Cactus I and Cactus II assets.
Great. Thank you. 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 one or two years. We've heard from others that E&Ps are kind of really only on the market for three to five years for recontracting as those contracts are coming up. But your high Corpus utilization might better position Plains than others. Wanted to get your thoughts there.
Jean Ann, we're in the middle of those discussions and have been for a while, it all depends on rate. At lower rates, we'd rather not have longer duration. We push for longer duration at higher rates. I think that's something between us and our customers. What I can tell you is we haven't seen any issues getting five year terms on for contracts that we like and customers like. I'd say we push towards the high end of that range.
Okay.
You know, Jean Ann, this is Willie. One other comment I would make is, remember our assets are an integrated asset base. When we look at, when Jeremy's team look at recontract extensions, it's really not just the long haul, it's the desire to integrate the gathering through the intrabasin, through long haul. We think we offer a more fulsome opportunity set for folks that wanna move barrels out.
That's helpful. If I can sneak in one more really quick one, if that's okay. Do you anticipate that the recent Energy Transfer acquisition of Lotus Midstream will have any material impact on Plains' businesses?
You know, 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.
Great. Thanks. That's all for me.
One moment for our next question. Our next question comes from Neel Mitra with Bank of America. Your line is open.
Hi, this is actually Neel Mitra. Thanks for taking the question. First, just wanted to ask regarding the NGL business. I know frac spreads have been really strong for the last kind of year and a half. Have you considered moving more to a fixed fee business just to create a little bit more stability longer term?
No. I, these assets that we're talking about are straddles. We have not looked to do that and don't anticipate that.
Got it. Maybe the second question for Jeremy. As you look at recontracting in 25 and 26, Corpus is getting a premium, but are 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'd get?
Neal, it's hard to speculate what would happen. The Enterprise noted that demand for that probably isn't until 2027, we're not sure what those markets look like. 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.
Corpus flows wouldn't be materially impacted, and you'd need the same amount of barrels to clear because the incremental demand is there. The reason for it being pushed is largely because Jean Ann mentioned lower contract durations. You need long-term contracts to get there. Docks are 40% to 50% utilized. Everything's moving and quality is maintained.
We struggle to see it in the near term w e do agree with Enterprise i f 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. If I could just clarify one question on the gathering 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? You know, would that put you kind of outside of the $300 to 400 million range at some point?
What was that range, Neil? I'm sorry. I just wanna make sure I answer the question properly.
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, Neil, is we're constantly debottlenecking and creating capacity. We announced earlier this year that there's probably $100 million of our capital program is to creating more capacity through stations and pipes.
We can always ship on other pipelines if it's a temporal need for additional capacity T he Wink to Webster segment between Wink and Midland will come on towards the end of this year. But large segments of pipe were in the neighborhood of $100 million to debottleneck the system. It's not 100 of millions.
We'll have lots of gathering capacity in and out. 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.
This is Willie. If you look at slide five, there's a good illustration of our operating leverage in the Permian. As Jeremy said, we're constantly trying to optimize the system to be able to get more out of it. I think it'll be a number of years before we hit constraints, meaningful constraints.
Okay, perfect. Thank you for all the color.
One moment for our next question. Our next question comes from Jeremy Tonet with J.P. Morgan. Your line is open.
Hey, guys. This is Ross, again, for Jeremy. just curious, looking past 2023, how you guys think about risk to long-haul intrabasin risk gathering volumes and, when you guys might see capacity becoming tighter? Thanks.
Great. On the gathering side, we're always constantly moving with volume and producers. I'd say that is one where we're just trying to stay ahead of the producers, and we'll have an active program to move constraints, as Willy mentioned.
intrabasin is one, depending on where volumes flows go, you can see constraints, but we work with our partners and try to resolve that. That's where you might see the investments Neil was talking about, is intrabasin. If more needs to go to Houston or Corpus, do we need to expand capacity in one place or direction? I would say that that's transient, and there's a big piece coming online toward the end of this year that we could ship on if we needed incremental capacity.
There might be some intrabasin constraints, but we have ways to resolve them, and those investments are being made. The last one is on the long-haul side. You know, it depends on by market, right? As I mentioned, all markets are needed. You're 90%-plus utilized to Corpus, but there's plenty of places for the barrels to flow. They can flow to Houston, they can flow to Nederland, they can flow to Cushing.
Over time, the differentials today are inside of where they would support incremental investment and expansion. You would probably need to see rates move first before you saw incremental expansion. That's probably a couple years away before you would need incremental expansion from here on the long-haul side.
Okay, great.
Maybe just as a reminder, as you think about long-haul, there's about 8 MMbpd 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. 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, you know, the costs go up. That's part of the reason that we think that margins ultimately have to get stronger as we go forward.
Great. Thanks for all the color there. 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's 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 it'll begin operation this summer i t's a modest investment, less than $10 million. We're looking at a number of different areas, whether that's renewable power generation behind, you know, the meter at our existing facilities, converting existing assets or pipelines, even things like hydrogen storage underground.
In particular, our Canada storage position lends itself to opportunities to store hydrogen. 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.
Got it. I'll leave it there.
One moment for our next question. Our next question comes from Gabriel Moreen with Mizuho. Your line is open.
Hey, good morning, guys. Maybe if I can ask kind of a two-pronged Canadian crude oil question. One is just, can you just characterize for us where we are sort of in the ramp on Capline volumes and how that asset is going? Then maybe a little premature to ask this, but assuming Trans Mountain starts up early next year, can you just talk about how well insulated your pipes are, your crude oil pipes are coming out of Canada from that start-up?
Sure. On the Capline front, we've seen quite a bit of demand from the existing shippers and the same game refiners. It's 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. On the TMX start-up, 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? That's largely not getting exported out of the Gulf Coast.
That could bring either additional imports or it could bring additional barrels to the MidCon refining complex that soaks a lot of that up t hat could support our Basin Pipeline and our MidCon i t 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 them t hey could have some imports, but largely we'd expect quite a bit of those barrels to move.
Our Canadian assets are largely insulated t hose are largely gathering assets into the mainline. If the differentials would tighten, that would increase the realized price and incent more production and volume to come. 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 along the systems.
Thank you. maybe if I could just get an update sort of on the Line 901 receivable, if there's any, an update there?
No update. We've submitted the claim. Parts of the claim has been denied, and we are proceeding with arbitration. We feel strongly with the merits of our position and expect to collect in full, although it'll take some time, and we've modeled it into early 2024.
Thanks all.
One moment for our next question. Our next question comes from Neal Dingmann with Truist. Your line is open.
Hi, this is Jake Nivison on for Neal. Thanks for the question. I just wanted to go back to the customer contracts. I know you mentioned, you know, the duration that, you know, the color that you provided there i just wanted to get a sense. Could you remind us, I guess, what time of year, you know, typically do these customer contracts, you know, get reevaluated? I guess could you provide, if possible, a quantification of, I guess, what percent of those contracts are up for renewal?
Yeah. Neal, thanks for your time. Candidly it's fluid because each contract has notification periods, whether it's cancellation or options w e really can't. A lot of that's driven by when time of year the pipeline's in service t here's not a contracting season like there is for NGL sales or purchases. We've recontracted a lot of those producers for long periods of time, substantially longer than their long-haul contracts on our gathering systems with the intent it's just a matter of price when we get to the long-haul peak.
We have open lines of communication and dialogue, and we'll update. It's a function of price when it gets to where we're willing to do something and they feel it's appropriate to do it w e feel very good about the volume on the pipelines and that we will continue to recontract the pipes and the utilization support that. I don't know if there's anything to add there, but that's all I can give you at this time.
Sure. Thank you. Just a quick, you know, follow-up here. I know you guys mentioned hedges in 2023, I guess about, like, 80%. Do you have any update on 2024 hedges? Have you guys added anything recently there?
I assume you're talking about natural gas liquids t he answer is we haven't given any guidance on 2024.
Gotcha. Okay. Thank you very much.
One moment for our next question. Our next question comes from Sunil Sibal with Seaport Global. Your line is open.
Yeah. Hi, good morning, everybody. Thanks for the clarity on the call. I was curious, you know, seems like upstream M&A, especially in Permian, has picked up pace. I was curious, you know, how does that impact Plains especially, you know, with regard to your negotiations on recontracting and more broadly, you know, the integrated model that Plains has had so much success with in Permian?
Jeremy?
Sure. Sunil, take it a couple steps. M&A has been happening for a long time in the Permian. The bigger the customer, the more they're largely driven to us and the integrated nature and more options t hat'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 lean into that. By and large, everyone's happy in the end i 'd 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 gonna get drilled, that 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.
While it is on the surface reducing rigs, they're private equity adding rigs. That's why you see stability in the rig count. Some of it's a positive for us as we see incremental production in places where we weren't seeing it before.
Got it. Thanks for that. Then, you know, when I look at your commodity price assumptions, it seems to me that the Canadian AECO price assumption of CAD 3.50 million per gigajoule is probably one of the biggest kind of variables. Is that kind of thinking correct? If so, any sensitivity on that price to your NGL segment?
You know, Sunil, we've got a pretty good sensitivity on that we disclosed on one of the slides w hat I would tell you got AECO. There's a lot of pieces that fit into that. You got AECO, you've got the, 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. I would just go back to the kind of the rule of thumb that we have, which is on an annual basis, $0.01's worth about $7 million of frac spread.
On an annual basis.
On a clean year, right.
Okay, thanks.
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 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.