q4 2023 plains all american pipeline lp and plains gp holdings lp combined earnings call

Q4 2023 Plains All American Pipeline LP and Plains GP Holdings LP combined Earnings Call

q4 2023 plains all american pipeline lp and plains gp holdings lp combined earnings call

Participants

Al P. Swanson; Executive VP & CFO of Plains All American GP LLC; Plains All American Pipeline, L.P.

Blake Michael Fernandez; VP of IR; Plains All American Pipeline, L.P.

Jeremy L. Goebel; Executive VP & Chief Commercial Officer of Plains All American GP LLC; Plains All American Pipeline, L.P.

Wilfred C.W. Chiang; CEO & Chairman of Plains All American GP LLC; Plains All American Pipeline, L.P.

Brian Patrick Reynolds; Analyst; UBS Investment Bank, Research Division

Indraneel Mitra; Analyst; BofA Securities, Research Division

Jean Ann Salisbury; Senior Analyst; Sanford C. Bernstein & Co., LLC., Research Division

John Ross Mackay; Research Analyst; Goldman Sachs Group, Inc., Research Division

Keith T. Stanley; Research Analyst; Wolfe Research, LLC

Michael Jacob Blum; MD and Senior Analyst; Wells Fargo Securities, LLC, Research Division

Neal David Dingmann; MD; Truist Securities, Inc., Research Division

Sunil K. Sibal; MD & Senior Energy Infrastructure Analyst; Seaport Global Securities LLC

Theresa Chen

Timm Schneider

Vrathan Reddy; Analyst; JPMorgan Chase & Co, Research Division

Presentation

Operator

Good day, and thank you for standing by. Welcome to the PAA and PAGP Fourth Quarter 2023 Earnings Conference Call. (Operator Instructions) Please be advised that today’s conference is being recorded.
I would now like to hand the conference over to your speaker today, Blake Fernandez, Vice President of Investor Relations. Please go ahead.

Blake Michael Fernandez

Thank you, Daniel. Good morning, and welcome to Plains All American Fourth Quarter 2023 Earnings Call. Today’s slide presentation is posted on the Investor Relations website under the News and Events section at plains.com. 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. An overview of today’s call is provided on Slide 3. A condensed consolidating balance sheet for PAGP and other reference materials are 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.

Wilfred C.W. Chiang

Thank you, Blake. Good morning, everyone, and thank you for joining us. Today, we reported fourth quarter and full year results exceeding expectations in both our Crude Oil and NGL segments. We’ve made considerable progress towards our long-term strategy, while demonstrating continuous execution of our goals and initiatives.
In summary, fourth quarter and full year adjusted EBITDA attributable to PAA was $737 million and $2.71 billion, respectively, with full year results exceeding the midpoint of our initial guidance by approximately $210 million or 8%. We lowered our long-term leverage ratio target range to 3.25x to 3.75x, and we ended 2023 with a leverage ratio of 3.1x. Our efforts to enhance the balance sheet were recognized by the credit rating agencies with 2 recent upgrades to mid-BBB.
Additionally, we completed several win-win strategic transactions in both of our — both in our Crude Oil and NGL segments and including 3 Permian gathering bolt-on transactions, the sale of our interest in a Canadian fractionation facility and the recent divestiture of approximately 600 crude oil railcars for proceeds of approximately $40 million. These transactions are representative of our ongoing efforts to optimize our asset base and streamline our operations, while generating attractive returns for unitholders.
The strong EBITDA results, along with the recent bolt-on transactions and lower leverage, helped underpin a $0.20 per unit annualized increase in our common unit distribution level, which will be payable later this month, and represents a 19% increase in the annualized distribution relative to 2023 levels.
Turning to Slide 4, it should come as no surprise that our 2024 key focus areas remain very consistent with last year’s. Our strong operational and equity performance over the past year only serves to reaffirm our strategy, most notably, our focus on generating meaningful free cash flow, our commitment to capital discipline, and a clear and concise capital allocation framework, focused on increasing return of capital to equity holders, while maintaining a strong balance sheet and financial flexibility.
As highlighted on Slide 5, we expect adjusted EBITDA attributable to PAA of $2.625 billion to $2.725 billion for 2024. This reflects year-over-year growth in our Crude Oil segment, underpinned by continued Permian production and tariff volume growth, as well as contributions from recent bolt-on acquisitions. Our guidance also factors in a reduction in our NGL segment, primarily driven by lower forecasted frac spreads year-over-year.
As shown on Slide 6, we anticipate 2024 Permian crude oil production growth to be between 200,000 to 300,000 barrels a day exit to exit, with the Delaware Basin driving the majority of the growth. Our updated forecast assumes an average of 300 to 320 horizontal rigs. And as part of our routine fundamentals forecasting process, we will continue monitoring our assumptions as the year progresses. Our Permian JV system is well positioned with more than 4.4 million long-term dedicated acres and operating leverage to provide customers with midstream solutions from the wellhead to demand centers.
As we show on Slide 7, we expect to capture approximately 275,000 barrels a day of incremental gathering tariff volumes for the full year 2024. For our long-haul systems, we continue to expect high utilization on our [Corpus-bound] assets, a volume step-up on Basin Pipeline and an MVC step-up on Wink to Webster.
In our NGL segment, we continue to focus on optimizing the business and improving the durability of our earnings. During 2023, we closed the sale of our JV interest in Keyera Fort Sask, and we sanctioned a 30,000 barrel a day debottleneck of the Plains Fort Sask complex. The debottleneck project remains on budget and unchanged in service date of mid-2025.
With that, I’ll turn the call over to Al.

Al P. Swanson

Thanks, Willie. We reported fourth quarter adjusted EBITDA of $737 million, which includes Crude Oil segment benefits from Canadian market-based opportunities and increased volumes across our systems, primarily in the Permian, along with NGL segment benefits from stronger seasonal sales and higher realized frac spreads. For the full year, we reported adjusted EBITDA of $2.71 billion. Strong full year performance was primarily driven by higher realized frac spreads, market-based opportunities, strong base business performance and contributions from bolt-on acquisitions. Slides 13 and 14 in today’s appendix contains walks, which provide details on our fourth quarter performance.
A summary of our 2024 guidance and key guidance assumptions are on slide eight. Looking at 2024 compared to 2023, and as illustrated on the — by the EBITDA walk on Slide 9, we expect adjusted EBITDA of $2.625 billion to $2.725 billion with year-over-year growth in our Crude Oil segment, partially offsetting commodity price headwinds in our NGL segment. Growth in our Crude Oil segment is primarily driven by anticipated tariff volume increases, higher fees from tariff escalators and full year contributions from bolt-on acquisitions. This is partially offset by our assumption of fewer market-based opportunities. We expect lower year-over-year NGL segment adjusted EBITDA, driven by lower forecasted frac spreads, partially offset by higher C3+ spec product sales in 2024. I would note that our C3+ spec product sales volumes are approximately 90% hedged for the year in the mid-$0.60 per gallon level.
We remain disciplined with our capital investments with approximately $375 million of growth capital and approximately $230 million of maintenance capital expected for the year net to PAA. This includes capital for POP JV well connections and intra-basin improvements, as well as an increase in our capital related to our previously announced Fort Sask debottleneck project.
As illustrated on Slide 10, and in addition to a capital discipline, we remain committed to significant returns of capital and maintaining financial flexibility. For 2024, we expect to generate $1.65 billion of adjusted free cash flow, excluding changes in assets and liabilities, with approximately $1.15 billion to be allocated to common and preferred distributions, inclusive of the respective increases, resulting in $500 million of adjusted free cash flow after distributions available for value-creating opportunities, including potential bolt-on acquisitions or net debt reduction. Regarding our senior note maturity profile, we have $750 million of notes maturing in November 2024, which we would expect to refinance all or a portion of during the year.
With that, I’ll turn the call back to Willie.

Wilfred C.W. Chiang

Thanks, Al. Ongoing geopolitical turmoil continues to drive market volatility, along with potential impacts to energy and economic policy. Despite this environment, Plains is well positioned today and going forward to continue delivering value to our unitholders.
As we show on Slide 11, we’ve made meaningful progress on our long-term goals and initiatives to continue to reposition — to position ourselves to be the partner, employer and the investment of choice.
In summary, our balance sheet is much stronger with year-end 2023 leverage at 3.1x. We continue to demonstrate capital discipline and patience as we look at additional opportunities to grow the business organically and inorganically through accretive and synergistic bolt-on acquisitions. And last but not least, we remain focused on increasing return of capital to our unitholders. We believe the world needs North American energy supply long term and that our business will perform well in both the near-term and longer-term environment.
I’ll turn the call back over to Blake, who can lead us into Q&A.

Blake Michael Fernandez

Thanks, Willie. (Operator Instructions) With that, Daniel, I’ll turn the call over to you.

Question and Answer Session

Operator

(Operator Instructions) Our first question comes from Michael Blum with Wells Fargo.

Michael Jacob Blum

I wanted to ask a little bit on the 24 guidance. Your Permian basin-level growth forecast, it’s pretty close to your own gathering volume growth estimate. And I’m just wondering if you could speak to that. Is that a function of your market share in the basin? Is that just a coincidence? And then, the guidance also assumes a pretty nice jump in Western volumes year-over-year. So I wonder if you can talk about what’s driving that as well.

Wilfred C.W. Chiang

Yes. Michael, this is Willie. The 275,000, maybe for clarity, it’s composed of 2 factors. One, the M&A, the bolt-on transaction volumes that we added last year, and that’s about 150,000 barrels a day, and then growth from the growing basin, which is about 125,000 barrels a day.
And on the Western volumes, Jeremy, you want to comment on that?

Jeremy L. Goebel

Yes. If you’re speaking about Delaware Basin volumes being Western California, that was due to some downtime at the beginning of last year. So it’s basically just normalizing to the second half of the year runway and some shutdown from California refineries, which pushed more volumes to the pipe. So it’s a combination of those 2 things.

Michael Jacob Blum

Okay. Perfect. Appreciate all that. And then, just wanted to ask, it seems like the open season on Gray Oak is moving forward. So, just want to get your views on how you see that impacting your recontracting efforts on Cactus and then just generally on overall supply versus takeaway out of the basin.

Jeremy L. Goebel

Sure. So what I would say first is, [with respect to] open season, we expect it to be successful. We are continuing to have constructive dialogue with our customers and see no reason why that’s going to impact our recontracting negotiations. As far as takeaway from the basin, pipes to Corpus, they’re still full. Wink to Webster is still full. You had some flex on a few pipelines in the area, but as basin grow, that will tighten. But it’s a constructive market. People know where they want to bring their barrels in the future, and we’re — and we will continue to be positive on the long-haul pipes as time goes.

Operator

Our next question comes from Brian Reynolds with UBS.

Brian Patrick Reynolds

Maybe to follow up on Michael’s question on just the 300,000 barrels of Delaware growth, which you bifurcated between some organic and inorganic year-over-year, just given high-level, Plains has 50% of the market share in the Permian, of which I think you’re more highly leveraged to Delaware, just kind of curious if you can help us kind of square out kind of that gathering and long-haul guide a little bit more. Do you see outsized gathering share opportunities in the Delaware? Just given that more growth is expected to come from there in ’24.

Jeremy L. Goebel

I think Willie outlined the sources of the gathering growth, specifically Midland versus Delaware. It’s a function of activity. So if you look at the number of rigs working in Delaware, it’s probably 170 to 180. You have closer to 120 working in Midland. When you offset declines in new production, that’s what yields the growth. You had significant growth in the fourth quarter of last year. So you would imagine it to be slower in the first half, stronger in the second half, which is consistent with some of the public E&Ps that have guided so far this year. So the Delaware Basin growth is a function of activity. We do have a stronger position in the Delaware Basin. So, that impacts us disproportionately. So I’d say that’s that piece. That’s for the long-haul guide. I think you were referring to the fourth quarter versus the full year long-haul numbers. And what I would say there is, we had an outsized contribution from the basin in the fourth quarter and a more normalized view for the year next year.

Brian Patrick Reynolds

Appreciate all that. Maybe as my follow-up, switch to capital allocation. Plains enters ’24 with a similar Tier 1 free cash flow yield in the space similar to ’23. Last year, we saw debt reduction and some opportunistic M&A, along with the distribution bump. So kind of curious, as we look ahead to ’24, preferences of that excess cash. And specifically on M&A, do you see a similar amount of like bolt-on opportunities in ’24? Are they more limited at this juncture to where debt reduction might be the preference?

Al P. Swanson

Sure. This is Al. Our focus will be to continue to look at potential to make investments that are accretive to our valuation. We’re hopeful that we’ll be successful on some bolt-on acquisitions, but we don’t know. We feel, in the near term, if we aren’t successful with that, then again, continuing to reduce debt is not a bad alternative, pending that opportunity set. We do not specifically believe that we need to continue to reduce debt. However, our priority will continue to be to focus on investing, returning more cash through distributions and looking for other value opportunities around using that cash flow.

Wilfred C.W. Chiang

Brian, this is Willie. Maybe I’ll add something to what Al said. When you think about the evolution of where we are, I’m not saying anything people don’t know, but it’s pretty remarkable where the industry has gone as far as shifting to an export market. A lot of capital has gone into the industry in the last decade. And I think what we’re seeing right now is really kind of a change in the business cycle, focus on returns, which really is going to reinforce more opportunities for asset sales, consolidation. And really to address your question, I do think there are going to be more opportunities in there. And frankly, we just need to be very patient and capture it. Our asset base, as you know, is well situated to be able to capture synergies across the system in many of the basins we operate, but particularly the Permian. And the key now is to stay very disciplined. And at the right valuations, I think we can add bolt-ons just as we did last year.

Operator

And our next question comes from Keith Stanley with Wolfe.

Keith T. Stanley

Could you, maybe on Cactus, just give a little more color on where you are at working to recontract that pipeline, timing of when you hope to resolve it and high-level goals for that? And I guess, just big picture, how you’re thinking about a desire to have contracts with medium-term duration versus operating the pipeline on a less contracted basis depending on where price settles out?

Jeremy L. Goebel

Keith, this is Jeremy. What I would say is, it’s constructive for us to have those dialogues now versus where it was the last couple of years. We expect to give you guys an update on that this year. But for competitive reasons, it doesn’t make sense to right now. What I would say is, there’s usually a mix, and it’s largely — we have to clear the basin. These pipes need to move barrels every day. And the owners of the capacity on that pipeline should be someone with ratable export takeaway because that’s where it’s going. So in a lot of respects, it makes sense to contract those pipelines with the third parties that will be exporting the barrels. So we serve the function of aggregating barrels from the lease to the market center. We have the liquidity in our terminals. They like to partner with us. It’s matching up the supply on one end with their takeaway on the other. So it needs to have to strike a good balance of contracting with third parties and some marketing opportunities. But for us, it’s more weighted to contracting and partnering up with the offtakers, like in Wink to Webster with the refiners, like on our Corpus pipelines with the exporters.

Wilfred C.W. Chiang

And Keith, just to make a — reinforce the point that Jerry made, many people we talk to think that our partners could disappear. We’ve got great partners on this line, folks that are shipping. And so, the way I would couch this is, we’ve got a great relationship with our partners and the shippers on the line. And this is just a normal course of business that you have to go on renegotiation and negotiations as far as term and tariff.

Keith T. Stanley

Got it. Second question, just the company has had really good market-based results in the past 2 years on Canadian crude spreads and NGL market dynamics. I think it’s Slide 9. You’re assuming fewer market- based opportunities in 2024. Is that a function of there are specific areas where you just see less opportunity this year? Or is it just conservatism built in/kind of a lack of visibility at this point? Just how you would characterize that bucket on market-based opportunities?

Wilfred C.W. Chiang

Yes. So market-based opportunities, you can’t predict them. They’re very difficult to figure out. When something might happen, some of this is weather. Some of it’s other asset-relied. And there’s all kinds of things that factor into this. And we’ve been pretty conscious of not trying to forecast in a large capture for things that we don’t know that’s going to happen. So one of the fundamental changes this year is we have — not we, but the industry has Trans Mountain that’s starting up that could impact the opportunities for crude market opportunities. So we factor all this in. And to answer your question, we don’t have a tremendous amount of — we have a modest amount of market opportunities that we have captured, that we think we can probably catch. The answer is, if there are opportunities out there, it’s in our ethos and DNA to capture markets. We’ve got the broad assets and a company with people that focus on this every day. And so, if there are opportunities out there, we’ll capture it. But it’s very difficult to predict exactly where they happen. And again, this year’s budget is based on a modest amount of market opportunities, and that’s frankly why we move towards the range to give people kind of a range of thought of what those might be. I hope that helps.

Keith T. Stanley

It does.

Operator

And our next question comes from Jean Salisbury with Bernstein.

Jean Ann Salisbury

Can you talk through the puts and takes of TMX starting up on Plains’ various assets, Canada — your Canada crude pipelines, flows to Cushing, et cetera?

Jeremy L. Goebel

Jean, it’s Jeremy. It’s a function of time, so it’s not just linear. But the startup, you would imagine there’d be less market-based opportunities, but there’ll be the opportunity for more production growth in the basin. It will offset some current flows like rail from the Williston or exports of heavy from the Gulf Coast first. And then, you’ll have replacement of — in our opinion, you’ll have replacement of production growth in Canada. So in that initial period, there’ll be less market-based opportunities. Depending upon the flows that go West, if it’s lighter barrels or heavy barrels, that could impact flows to the Midwest of basin barrels or other light barrels. So there are opportunities. We’re going to have to wait for it to start up and transition into full capacity that can be reached and what those flows will impact all those components. But we have a flexible system. We’re touching all parts of that value chain. So if it’s fee-based growth on the gathering systems, we’re excited about that. As the basin tightens again and market opportunities come back, that’s fine for us, too. But we’ll be there wherever the opportunities present themselves.

Jean Ann Salisbury

Okay. And just a kind of similar follow-up. Some Bakken contracts begin to roll this year on Double H and DAPL going out of the Bakken. Do you anticipate any major change in how much Bakken crude makes its way kind of the westbound route down to Saddlehorn or the Cushing market or other things that could impact Plains’ EBITDA?

Jeremy L. Goebel

Sure. So there’s a few things that impact it. There are certain gathering systems that feed South and certain that feed into the DAPL system. But outside of those, those [jump ball] barrels, I think it will just be competitive between the groups that head south and the groups that head to the Gulf Coast and Patoka. So we’re [there, patient]. We talk to our customers. Saddlehorn is largely full from DJ Basin. It has some movements from Guernsey, and those opportunities are presenting themselves. And so, we’ll continue to work with shippers to bring them South if it makes sense. But there should be plenty of barrels to go around in that area.

Operator

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

Indraneel Mitra

I wanted to touch on the 90% of NGL frac spreads that are hedged for ’24. Obviously, frac spreads have trended up lately. I was wondering if you’re able to catch some of that with the incremental hedges you put on. And how are you looking at perhaps hedging more than usual and maybe going up to 100% if you’re content with this frac spread environment right now?

Jeremy L. Goebel

So, Neel, first thing, it’s really backwardated. And until natural gas prices tanked a few weeks ago, it was substantially lower. So this is relatively new, and it’s much higher in the front. I think 2025 is $0.56, $0.57 and prompt could be at $0.80. So, that backwardation prevents a lot of forward hedging. Our hedges are consistent with what Al said, in the mid-60s at roughly 90%. And what you could say is that the hedging profile for us is somewhat consistent with the forward market. So we’re higher hedged in the front and lower hedged in the back end of the year, if that’s helpful.

Indraneel Mitra

Okay. And then second question, Jeremy, maybe just if there’s a way to kind of bridge where the Midland-MEH spread is right now for ’25 and where you’re looking to contract and how we should look at it on a contract basis versus a spread basis, when you’re signing up these contracts?

Jeremy L. Goebel

Sure. What I would tell you, Neel, is most of these contracts are for the latter half of ’25 and forward. So we’re not really looking at the ’25 market. We’re looking at more what is the constructive long-term rate to ship barrels from the Permian to the Gulf Coast. And so, that’s between us and the shippers, but we’re having constructive dialogue and we’re less worried about ’24 and ’25 and more what the long-term rate is after the contracts roll.

Indraneel Mitra

And when you talk to your counterparties, would it be 3 to 5-year contracts typically? Or are you looking longer (inaudible)?

Jeremy L. Goebel

I think we’ll — Neel, what I would suggest is, we’ll give you an update later in the year and give you more information.

Operator

Our next question comes from Jeremy Tonet with JPMorgan Securities.

Vrathan Reddy

This is Vrathan Reddy on for Jeremy. For my first one, I just wanted to ask on more color on the 2024 intra-basin and long-haul volumes. It looks like the ’24 guide is down versus the 4Q ’23 rates. So if you could discuss drivers there? And as maybe a second part to that question, do the long-haul shipments include the 50,000 barrel per day shipments that have already been prepaid?

Jeremy L. Goebel

I’m going to go back and look for your question here. So you said inter-basin volumes on the guide versus long-haul. So I’m looking at Q4 long-haul and intra-basin, and then for next year. I would say there’s probably some noise in that. Q4 had a bunch of flush production. Some of that volume with Wink to Webster connecting (inaudible) and volume will go in that direction, which is actually a positive because those are shorter-haul tariffs and that leads for integrated movements on our gathering system. So I’d say this is all consistent with our guidance and constructive for volume growth out of the Delaware Basin. And then, on the long-haul side, I believe I answered that question earlier. It was just a surge in basin production in the fourth quarter and more normalized for the rest of the year.

Vrathan Reddy

And then, for the second one, it looks like Plains is approaching the long-term distribution coverage target. So just could you walk through how you guys think about distribution progression from here may be versus a step-up and then flattening out or a more ratable moderate step-up in the future?

Al P. Swanson

Well, I think our current guidance for this year shows 190% coverage. So we’ve got a bit to go. Our stated approach will be $0.15 a year until we hit the 160%. And then DCF growth will drive future increases there. So we haven’t provided guidance for ’25 or ’26 yet. But yes, with this 19% or 20% increase we just did, we’re still at 190% coverage.

Operator

Our next question comes from Sunil Sibal with Seaport Global.

Sunil K. Sibal

So I just wanted to dwell a little bit on your gathering volumes. Could you give us a sense of your gathering volumes in Permian, roughly what percentage of that comes from your dedicated acreage versus acreage where you may be competing for volumes?

Wilfred C.W. Chiang

Sunil, this is Willie. I don’t know if you were on earlier, but the overall gathering volume increases are 275,000 barrels a day. 150,000 of it’s from the bolt-ons that we did. The remainder of the growth, 125,000 is all — really all Delaware Basin growth.

Sunil K. Sibal

Okay. No, I was actually referring to your current gathering volumes. I was curious in Permian, is there a good sense of what all comes from your dedicated acreages in Permian versus acreages where you may be competing for those gathering volumes?

Jeremy L. Goebel

Sunil, I would say the vast majority is associated with the 4.4 million acres that Willie referenced in the script that are dedicated to the system.

Sunil K. Sibal

Understood. And then, on the M&A front, it seems like you divested some assets in 2023. Could you give us a sense of, from an opportunistic M&A perspective, where do you see the most value, either basin-wise or asset-wise?

Wilfred C.W. Chiang

Sunil, that’s probably something we’re not going to comment on all the what-ifs. I can assure you that we look at — we run models on all kinds of different things. We look at all the different assets and opportunities to create value for our unitholders. And on the same token, we look to optimize our own asset base, as we’ve proven over the last number of years. So it’s a dynamic activity that happens every day. It’s really hard to focus on valuations in different basins. So we’ll have to — maybe we can follow up with you offline and see if we can answer your question a little bit better.

Operator

Our next question comes from Neal Dingmann with Truist Securities.

Neal David Dingmann

My question, maybe, Willie, for you, or Al, just on Permian volume expectations. Al did a good job. You mentioned the rig count, which continues to be nice and stable. But to me, what seems to get a bit lost is the improved continued D&C efficiencies that happens to result in more volumes even with these similar levels. So I’m just wondering, do you all continue to see this type of upside as I do? Even if the D&C — if the rigs stay relatively stable, are you still expecting some nice volume upside on your part?

Jeremy L. Goebel

I think our forecast is consistent with what the industry is doing today, but they’re all working to get better. If you look at oil in place targets, and they’re achieving in first recovery is less than 10%. They’re trying to get higher than that. And if they do that, that would be where a big movement would be. What I would say though is, consistent with our view of supply and demand and current D&C practices, I would agree with you that there’s probably been 10% efficiency of just drilling completion time since the steadying out of the rig count. So this 300 rigs is probably doing the work of close to 330 rigs 12 months ago. But as far as recoveries, I think recoveries and our view of efficiencies are built into our forecast this year. But longer term, our bet would be on the U.S. E&Ps that they would figure out how to get higher recoveries.

Wilfred C.W. Chiang

And Neal, remember, we do a top-down assessment. We also — we have our connection forecast. It’s kind of a bottoms-up. And so, we factor all that together, and that’s where we got our number from.

Neal David Dingmann

Great point. Yes, that’s good to have that detail. And then, my second question is just maybe on the NGL segment, specifically, it looks like — just wondering how you think about is the sort of levels, now that propane — we’re through the — a bit through the season, it seems to me — do you think we’ll have more propane pricing pressure? And I guess I’m just wondering how you think that’s going to impact the regional basis differentials and maybe some more spot opportunities you all might have.

Jeremy L. Goebel

Sure. I think that’s a function of location. So Fort Sask is limited on fractionation capacity, which is why we’re expanding and our peers. So there could be some pressure on Y-Grade prices there. I’d say in the Gulf Coast, production growth will continue on the NGL side as associated gas and other gas grows — sources grow. And so, there needs to be some expansion of dock capacity and fracs in the Gulf Coast. So you could see some issues there. But in a lot of those locations where we sell our NGLs, they’re structurally short and inability to bring additional capacity into. So we’ll continue to try to sell into those markets and maximize basis.

Operator

And our next question comes from John Mackay with Goldman Sachs.

John Ross Mackay

I wanted to touch again on Permian crude, just on your — you commented on your bottoms-up estimates. I’d be curious if you could give us a bit of a read on what you’re seeing for private versus public activity? And I think also related, last year on the call, you just gave a bit of your sensitivity to changes in basin production from an EBITDA basis, maybe just a refresh on that, too.

Jeremy L. Goebel

So John, your first question, private verse public, we’re not going to disclose any information from our customers. But generally, a lot of the private inventory has been sold into the public hands. And so, the privates are now buying back from the independent lesser loved assets and starting to redevelop again. But I’d focus on the public. It’s been consolidated to look at their growth forecast, and that’s largely consistent with our forecast.
And as far as the EBITDA refresh, I’m not sure I caught that question.

John Ross Mackay

Yes. I guess last year, on the call, you said maybe like 100,000 barrel a day swing for the basin would be like a $10 million to $15 million EBITDA impact. Just curious if that number is still fair for ’24? Or are there some other moving pieces in there to refresh?

Jeremy L. Goebel

Yes, sir. That’s consistent with the contracting profile we have. So there’s not a lot of churn in the contract, so it doesn’t really change much.

John Ross Mackay

And then, just a follow-up, kind of staying on the same theme, but when you guys did the Oryx buy in, part of the narrative was, hey, eventually, over time, we should be able to use this bigger footprint to flow more volumes into our long-haul side. Just curious if you could give us a bit of an update there. And maybe if we look at your ratio of kind of gathering to long-haul volumes going forward, maybe how that ratio changes from here or not?

Jeremy L. Goebel

Well, one thing is, I wouldn’t consider the Oryx a buy-in, right? That’s our partner, and we’ve merged those assets together. So I just want to make sure we’re clear on that. But second, the JV has done exactly what we thought it would. And I would say it’s bolstered our relationship with our customers across the basin and given us the opportunity to provide integrated economics. But as for — the markets will dictate where barrels flow and pricing dictates where they flow. And so, we have strong relationships and the ability to contract our pipes, but they can only be so full. And so, barrels have to flow in other directions as well. And we’re completely comfortable with that.

Operator

Our next question comes from Theresa Chen with Barclays.

Theresa Chen

I had a quick follow-up related to Jean’s earlier question on TMX’s impact on your crude marketing business. Completely understanding that the differentials to both Mid-Con and Gulf Coast should be constrained, especially upon linefill, but as TMX delivers barrels to the West Coast, backing out some of the Middle East and LatAm imports, and given your liquids infrastructure business there, as well as your marketing presence, is that potentially a source of upside to crude marketing in 2024 relative to opportunities in 2023 as those waterborne imports are backed out and the flows and differentials change in California?

Wilfred C.W. Chiang

Theresa, this is Willie. It’s a complex question that, that’s hard to put a pin to. What I can assure you is that we have a very flexible system in that wherever flows will go, I think we’ll be able to adapt to that and capture value perhaps in different parts of our system. Long term, I look at this as very constructive because with more takeaway capacity to the West Coast, I think it allows a better price signal to producers to be able to produce more. Short term, we could see some headwinds, but I can assure you that we’ll adapt to that. Whatever the markets are, we’re going to try to look and see how we can use our assets to capture value.

Operator

Our next question comes from Timm Schneider with The Schneider Capital Group.

Timm Schneider

Thanks for all the color on the Permian. Quick question for me, kind of higher-level question on the sector strategic initiatives. So we’ve seen a ton of M&A activity on the upstream side, really saw some of these blockbuster transactions. So I have 2 questions for you on this. Number one, how do you view upstream M&A specifically kind of for Plains and for the midstream sector? Is that good for you, bad for you, kind of neutral? And the second follow-up I have to that is, how do you think upstream M&A — the large-scale upstream M&A ultimately trickles through to midstream sector? Because we haven’t really seen any blockbuster transactions there, right? We’ve seen one big deal over the last, call it, 12 to 18 months that had some, call it, tax attributes to it. Or is it more so smaller bolt-ons, and that’s the way to go? So just curious as to what your thoughts are on that.

Wilfred C.W. Chiang

Well, Timm, a short answer on the question for upstream consolidation and the impact on Plains, with our asset base and the relationships we have, I don’t think it’s going to be a material impact on us. We work with, if not all, most of the large players. So we’ve got volumes that flow on our systems today, and they’re tied with contracts. And the way I think about it is, if you have stronger counterparties in tougher environments, we’re fine if they want to develop the Permian in a more thoughtful and efficient way because we’re a long-term company, and we want to be around for a long time. So whether or not the production comes this year, next year or the following year, the stability is probably a very positive thing for us.
And then, when you think about the midstream, my observations are, I do think the upstream is a bit ahead of us. I do think there will be some more consolidation. Assets are probably the easiest way to go. And again, as we — as you look at the landscape, there has been some M&A in the midstream, but I think we are in the part of the business cycle where there are more opportunities to be bigger and be stronger. Not that we aren’t a large enterprise, but we’ll evaluate different opportunities as we go, always with the unitholder in mind.

Operator

I’m showing no further questions at this time. I would now like to turn the call back over to management for closing remarks.

Wilfred C.W. Chiang

Well, listen, thanks to all of you for your interest in Plains, and we will look forward to updating you as the year progresses. Everyone, have a nice weekend. Thank you.

Operator

This concludes today’s conference call. Thank you for participating. You may now disconnect.

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