Targa Resources Corp. (TRGP) Q1 2023 Earnings Call Transcript
Good day, and thank you for standing by. Welcome to the Targa Resources Corp. First Quarter 2023 Earnings 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, Sanjay Lad, Vice President of Finance and Investor Relations. Please go ahead.
Thanks, Bella. Good morning, and welcome to the First Quarter 2023 Earnings Call for Targa Resources Corp.
The first quarter earnings release, along with the first quarter earnings supplement presentation for Targa Resources that accompany our call are available on our website at targaresources.com in the Investors section. In addition, an updated presentation has also been posted to our website.
Statements made during this call that might include Targa Resources’ expectations or predictions should be considered forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ please refer to our latest SEC filings.
Our speakers for the call today will be Matt Meloy, Chief Executive Officer; and Jen Kneale, Chief Financial Officer. Additionally, the following senior management team members will be available for Q&A. Pat McDonie, President, Gathering and Processing; Scott Pryor, President, Logistics and Transportation; and Bobby Muraro, Chief Commercial Officer.
And with that, I’ll now turn the call over to Matt.
Thanks, Sanjay, and good morning to everyone. This year is off to a strong start at Targa, and we are very proud of our execution across the company in the first quarter. In Q1, we had quarterly EBITDA that was up 50% over prior year with a lower common share count.
Record volumes in the Permian, record NGL transportation and fractionation volumes and strong LPG export volumes. We also finished construction and are in the process of bringing our Legacy II and plant fully online. And we are also returning an increasing amount of capital to our shareholders.
We increased our quarterly cash dividend by 43% and executed on $52 million of common share repurchases during the first quarter. With a strong first quarter complete and given the strength of the business fundamentals underpinning our assets, we remain comfortable with our full year 2023 adjusted EBITDA estimate despite natural gas and NGL prices being about 30% and 10% lower than the price assumptions underpinning our 2023 EBITDA guidance range.
Natural gas volumes across our Permian systems are growing. Our current aggregate volumes are over five billion cubic feet per day of reported inlet and are expected to ramp as we move through the year, driving incremental volumes through our integrated downstream assets.
We have four plants under construction in the Permian and are ordering long lead times for an additional two plants. Given our increasing Permian volumes and resulting NGL supply growth, we announced this morning that we are moving forward with a new 120,000 barrel per day fractionator Train 10 and at our Mont Belvieu complex, which is expected to be online in the first quarter of 2025.
With the addition of Train 10 and additional spending on long lead items for our next Permian plants, we now estimate full year 2023 growth CapEx spending to be between $2 billion and $2.2 billion. Investing in organic growth projects across our integrated footprint provides Targa with attractive returns and puts us in a strong position to continue to return incremental capital to our shareholders.
Let’s now discuss our operations in more detail. Starting in the Permian, high activity levels continue across our dedicated acreage. Our systems across the Midland and Delaware Basins averaged a record 4.8 billion cubic feet per day of reported inlet volumes during the quarter.
In Permian Midland, our system has essentially been running above nameplate capacity, absent the impact of first quarter winter weather and is currently operating up over 100 million cubic feet per day versus Q1 average inlet.
Our new Legacy II plant partially came online in late March, limited by electricity capacity to the site and is expected to be able to be fully available later this quarter. And kudos to our engineering and operations team for safely bringing the plant online ahead of schedule and on budget.
Our next Midland plant Greenwood remains on track to begin operations in late fourth quarter of 2023 and is expected to be highly utilized when it comes online. In Permian Delaware, inlet volumes across our system increased 5% sequentially. Activity in volumes across our Northern Delaware footprint are running strong, and we have bolstered our connectivity across our Delaware assets to handle the near-term growth.
Our Midway plan is close to completion and is expected to begin operations later in the second quarter. Our Wildcat 1 and Roadrunner II plants remain on track to begin operations in the first and second quarters of 2024, respectively. We continue to expect volume growth across both our Permian Midland and Delaware positions for the remainder of the year and well beyond.
Beyond those projects already announced and in progress, we are evaluating when we will need additional gas processing capacity in the Permian, and we are ordering long lead items for our next Midland and Delaware plant. To that end, some of you may have seen a filing with the Texas Railroad Commission around the proposed gas pipeline we call Apex.
This filing allows for preliminary survey work to be completed on proposed routes. Given how rapid we are growing with over 1 billion cubic feet of incremental residue gas from just the plants we currently have under construction, we continue to work to ensure sufficient residue take-away from the basin.
As we have said previously, we remain in position to support as needed residue pipes to get Permian gas to market, whether we are leading those efforts or participating with third parties. The next pipe is needed in both our producers and markets on the Gulf Coast are keenly aware of that need.
We are also continuing to add intra-basin connectivity and redundancy in both the Midland and Delaware to move residue gas from Targa plants to enhance flow assurance to get volumes from Targa assets to market. In our Central region and the Badlands volumes were sequentially flat during the quarter. Overall volumes remained steady as we are currently not seeing any material change in activity despite lower commodity prices.
Shifting to our Logistics and Transportation segment, Targa’s NGL transportation volumes were a record 537,000 barrels per day and fractionation volumes were a record 759,000 barrels per day during the first quarter.
With the ramp in supply volumes from our Permian systems and third parties, our Grand Prix deliveries into Mont Belvieu are currently averaging around 600,000 barrels per day with fractionation volumes currently running near capacity of around 800,000 barrels per day.
GCF will provide some much needed help when it is fully restarted in the first quarter of 2024 and we expect our Train 9 fractionator to open up highly utilized when it commences operations during the second quarter of 2024.
Our newly announced Train 10 with an in-service date of the first quarter of 2025 is expected to be much needed given the expected continued growth in our G&P business.
Turning to our LPG export business at our Galena Park facilities, we loaded an average of 11.2 million barrels per month during the first quarter as we benefited from increased demand from stronger global market conditions.
Our low-cost expansion project to increase our propane loading capabilities with an incremental one million barrels per month of capacity remains on track for mid-2023. We are well contracted across our export facility and continue to expect that 2023 will be a record year for LPG export volumes.
We remain excited about the long-term outlook at Targa. Looking ahead, we continue to execute on our strategic priorities will drive increasing EBITDA, a higher common dividend and reduced common share count while maintaining leverage within our target range. We announced this morning that our Board has approved a new $1 billion common share repurchase program, which provides us with flexibility going forward to continue to be opportunistic on repurchases.
Before I turn the call over to Jen to discuss our first quarter results in more detail, I would like to extend a thank you to the Targa team for their continued focus on safety and execution while continuing to provide best-in-class services to our customers.
Thanks, Matt. Good morning, everyone. Targa’s reported quarterly adjusted EBITDA for the first quarter was $941 million, increasing 12% sequentially as we benefited from increased optimization opportunities in our marketing and LPG export businesses, contribution from our recent acquisition of the remaining 25% interest in our Grand Prix NGL pipeline earlier this year and higher overall system volumes despite lower commodity prices.
As we think about the shape of quarterly adjusted EBITDA across 2023, given the benefits of optimization opportunities in Q1 and seasonality in some of our businesses, we currently expect second quarter adjusted EBITDA to be the lowest of the year, ramping from there as our system volumes continue to grow.
As Matt mentioned, for the first quarter, we declared a cash dividend of $0.50 per common share or $2 per share on an annualized basis, representing a 43% increase over the first quarter of 2022. Consistent with previous messaging, we expect to maintain the same quarterly dividend for the remainder of the year.
We also repurchased $52 million of common shares in the first quarter at a weighted average price of $71.82. As of quarter end, we had approximately $92 million remaining under our $500 million program and now also have a new $1 billion share repurchase program authorized and in place.
Our full year 2023 adjusted EBITDA estimate continues to be between $3.5 billion to $3.7 billion, and we expect year-end leverage around the midpoint of our long-term target leverage ratio range of three to 4x. At the end of the first quarter, our pro forma leverage ratio was approximately 3.5x. We are well hedged across all commodities for the balance of 2023 and continue to add hedges for 2024 and beyond.
Coupled with our fee floor contracts, we have significantly de-risked our earnings and cash flow outlook while preserving the upside when commodity prices increase. With our plans to move forward with the construction of frac Train 10 in Mont Belvieu, and acquiring long lead items for our next Permian gas plant, we now estimate 2023 growth capital spending between $2 billion and $2.2 billion. There is no change to our current year estimate for net maintenance capital spending of $175 million.
At quarter end, we had about $2.6 billion of available liquidity, which provides us with a lot of flexibility looking forward. Maintaining a strong investment-grade balance sheet across cycles continues to be a priority at Targa. We believe that a strong balance sheet and continued investment in high-return projects positions us to continue to prudently return an increasing amount of capital to our shareholders across cycles.
Lastly, I’d like to echo Matt and extend a thank you to our employees for their continued focus on safety while executing on our strategic priorities. And with that, I will turn the call back over to Sanjay.
Thanks, Jen. For the Q&A session, we finally ask that you limit to one question and one follow-up and reenter the lineup if you have additional questions. Bella, would you please open the line for Q&A?
[Operator Instructions] Our first question comes from the line of Michael Blum with Wells Fargo.
I wanted to ask about frac Train 10. Maybe just walk us through the thought process there. It seems like there’s a lot of frac capacity being added to the market right now. And as some people are starting to talk about pressure on rates. So how much of Train 9 is contracting and how much of Train 10 would be contracted or would you need to be contracted to move forward?
Michael, this is Scott. Our frac Train 10 will have a similar cost to our Train 9 facility. And as we stated in our remarks, Train 9 is expected to come online in the second quarter of 2024. Given the number of current plants that we have under construction in the Permian and our comments around ordering long lead items for additional plants, we will obviously need to with fractionation capacity for the expected production stemming from our own plants.
There have been times over the course of the last few quarters that in order to manage our inventories, the influx of volumes that are coming on to our system. There are times that we have been offloading volumes both on transportation as well as fractionation. So our belief is, is that we have a strong need for frac Train 9 as it comes online. And again, frac Train 10 is trying to stay ahead of the cadence of the number of plants that we are building on the upstream side, along with the overall growth that we’re seeing from the industry.
And just to add to that, Michael, this is Matt here. We see the underlying growth in our G&P business, and we’re pointing that to frac Train 9, 10 and the restart of GCF. So I would suspect others as they’re bringing additional fractionation on, they have volumes that they see from their customers and their contracts. We need to make sure we have sufficient fractionation capacity for our underlying G&P business so we can provide an integrated NGL service to our G&P customers.
Got it. And then I just wanted to ask about the increase in growth CapEx. It seems like you’re kind of moving towards that $2 billion a year, plus or minus level. Is that a fair way to think about the run rate going forward? And if not, where do you think that does kind of long-term shake out?
Yes. Michael, it is a little bit tough to do run rate as it does get lumpy during certain years when you have large long-haul NGL pipes, for example, that can be in and give you more runway.
I’d also say when we made the acquisition of the North Delaware assets in the summer of last year, there was not sufficient processing capacity. So we do have a little bit of catch-up here with five plants being kind of brought online and ordering long lead time for two, that’s likely a little bit heavy, if you were to do a multiyear model.
That said, I think we’re going to continue to have strong G&P growth. We’re going to be needing to continue to add plants. So it really comes down a little bit to the lumpiness of some of the larger projects and the timing of our processing plants. But with our underlying acreage position and strong producer contracts we have in the Permian as long as they keep growing, which we see for years to come, we’re going to continue to invest in gathering and processing plants, expanding NGL transportation, fractionation and export. But there could be some lumpiness from year-to-year.
And your next question comes from the line of Brian Reynolds with UBS.
Maybe just touch on the return of capital outlook just given the lumpiness in CapEx over the next two years. We saw some buyback in the quarter with likely some dividend increases for the next few years.
So just given the rising CapEx and EBITDA outlook for the next few years from these growth projects, was kind of curious if you could discuss how Targa’s balance sheet capacity moves over the next few years given that free cash flow after dividends is pretty flattish until ’25.
This is Jen, Brian. I think we have a very strong balance sheet right now sitting at the end of the quarter around the midpoint of our long-term leverage ratio target range despite making a $1 billion acquisition in the first quarter.
And we think that our capital spending really helps to create significant long-term shareholder value and position us to be able to return an increasing amount of capital to our shareholders. As Matt described in his answer to Michael, there is some lumpiness associated with our growth capital spending, particularly around our large projects like Daytona and that means that there are some periods where we may have less free cash flow than other periods.
But we believe that this sets us up to continue to execute on really where we already are, which is a road map that says we will continue to maintain a really strong balance sheet. We’ve got increasing year-over-year EBITDA growth really as far as we can see under a variety of scenarios and then also are able to return increasing amounts of capital to our shareholders through a significantly increasing dividend and also opportunistic share repurchases. I think that’s the road map that we’ve shown over the last couple of years, and I think that’s the road map that will continue to follow going forward.
Great. Appreciate that. And as a follow-up, it just seems like Targa is using — or going after a little bit more third-party contracts historically, it just seems like Targa was very much historically focused on its internal equity volumes for both the G&P and L&T side.
Curious if you could just opine further on some of these new third-party opportunities that you’re seeing? Is it specifically on the long-haul side or G&P as well. and whether this is a business strategy shift to win new business? Or is there perhaps just more industry cooperation to maximize asset utilization.
I’m not sure exactly which piece on the third party you’re referring to, but let me just kind of answer it generally. Here at Targa, we try and really service our existing customers and our gathering and processing business, but we have been for years to get more acreage positions, more underlying volumes in our G&P business to continue to grow that business and then move those NGLs downstream.
So we’ve been very active in managing our existing contracts and going after new customers, new areas in our G&P business. And I’d say the same goes for transportation, fractionation and export is we have a lot of those volumes from GMP moving into our system. Most of those volumes have been moving more towards GMP based on our downstream side versus just third parties that are unaffiliated with G&P. That’s been a trend that’s been continuing.
I don’t know that that’s really been changing. But that said, our downstream commercial team is still focused on trying to get new business, whether it’s for Grand Prix or for our fractionators to provide that level of service for customers, whether they’re our G&P customers or just downstream customers. So we’re continuing that effort. I don’t think that’s really changed for us.
Your next question comes from the line of Jeremy Tonet with JPMorgan.
Just wanted to come back to, I guess, CapEx and how you guys think about hurdle rates and accretion. Clearly, in this market, there’s greater scrutiny on all CapEx. And just wondering, even with the lower commodity prices, I guess, if you could give us a feeling for what type of operation you see here where your hurdle rates and right now? That would be very helpful.
Jeremy, this is Jen. We put an ROIC slide in our February materials, partially just to very explicitly highlight just how well, we believe we’ve been able to invest over the last several years, particularly in projects and opportunities that we consider core. And the spending that we’ve announced this morning with our frac Train 10 and also additional spending around another Permian gas plant is core.
Just like the spending that we’re already doing for additional gas plants, fractionation and NGL transportation is core to us. So I wouldn’t say that our hurdle rate has really shifted. Continues to be, call it, 5x to 7x. I think that we have been able to execute better than that, partially because our assets are so well utilized when they come online.
It feels like we’re almost behind every time a new asset comes online. So it’s base loaded very quickly, which creates incremental more incremental returns that accrue to us more quickly than maybe before when we grew into our capacity, maybe a little bit more slowly.
So I’d say that we continue to look at each and every opportunity and try to really scrub our capital spend plan are in a cycle right now where we are spending a little bit more and partially, that is a result of the lumpiness of some of our bigger projects. But ultimately, it’s really across our core value chain, and we believe it’s going to generate significant incremental returns for Targa and for our shareholders.
To the extent that we get into an environment where we see producer activities slow down, I think we’ve demonstrated a track record where we’ve rationalized spending before. When you think about our 2020 spending of $600 million, 2021 spending of just a little bit over $400 million. We clearly have executed previously, where if activity levels are lower, we rationalize our spend.
Currently, we just have a lot of expectations given the strength of the producers underlying our G&P systems for significant incremental volume growth. And that’s going to necessitate a digital volumes across both our G&P and logistics and transportation footprints.
Got it. That’s very helpful there. And then just wanted to dive in a little bit more on reaffirming the guidance here even with the big move in commodity prices. Just wondering if you could provide a little bit more color on some of the offset there.
Just wondering how you’re tracking versus the 10% Permian growth is you outlined there are better than that? And then also just LPG export trends seem pretty robust as well. So wondering if you could just help us think through some of those tailwinds.
We now have 1 quarter under our belt, so it’s always easier to affirm guidance when part of it is already accounted for. And I think Q1 was a really strong quarter for us across the board. Record volumes in a number of different areas, and our employees also did an excellent job of optimizing our assets and generating additional opportunities from our footprint.
So as we look out at the rest of the year, prices are lower, but I think we continue to see and expect excellent volume growth, again, really across all of our assets. And that’s really what is underpinning our reaffirmation of our guidance despite lower prices.
Your next question comes from the line of Tristan Richardson with Scotiabank.
Appreciate it, Matt. Maybe just a question on the residue side. You talked a little bit about Apex. Obviously, this is very early days here and really just emphasize the longer-term need for residue at a high level, but maybe kind of curious what this could look like in terms of potential end market destinations.
Maybe just a little bit more detail on what the preliminary plans for this look like, maybe timing, capital, et cetera? And just thinking about is this a project that you guys are full speed ahead on or really just exploring potential options?
Yes. Thanks, Tristan. Good question. What really underlines or underlies our overall strategy for residue is to make sure that there’s takeaway — and so we want to support whether it’s this Apex pipeline or others, we want to make sure that there’s takeaway. We have a lot of volumes in the Permian, a lot of plants coming online.
So for us to be able to charge a processing fee and the liquids down Grand Prix and into our frac, we need to make sure we’re processing those volumes. We need to make sure that there’s residue takeaway. So we are working — we’re doing some preliminary work on Apex. We’re also talking to other customers. But I’m going to turn it over to Bobby just to talk a little bit more about that project and what we’re thinking there.
Yes. So this is Bobby. At the end of day, what we want to see is we want to see all the residue move out of the Permian Basin. So whether it’s on a pipeline like Apex or a third-party pipeline or 1 that we’re a part of. We’ll just be excited to see pipelines go. And then as we think about what Apex could look like if it did go we ultimately have no shortage of residue supply to put to a pipe between us and our customers.
And I think everybody knows what’s going on with the market down there in that general vicinity of the state with LNG and other demand coming on. So as we think about that, the potential for that project to come together at some point in the future, kind of goes to what happens with other pipes what we end up doing on other pipes versus Apex and then what the market does down there and how it develops. Taking these things all up is a fairly complicated process.
And we just want to make sure that there are options out there that we can execute on to make sure the residue flows, whether it’s the pipe in ’26 that will be needed or a pipe that’s needed in ’28 as all those facilities down there in the Sabine River corridor come online and have a very strong demand for gas.
Appreciate it, Bobby. And then maybe just a follow-up. I think we all know the scale and the quality of your customers, both in the Midland and the Delaware. But maybe curious to the extent you’re seeing any discussion of change in development plans or responding to price signals in the market, even if it’s at the margin and on very small customers, but just any comments on maybe the long tail there.
Yes. This is Pat. Really, we haven’t had any change in activity. Activity levels remain high. rigs are running on acreage all around our system, on our system. We haven’t — the big guys obviously are disciplined. They tell you guys what they’re going to do, and they continue to execute on their plans.
Some of them are a little more back-loaded this year than in previous years. But the rigs are running the wells are getting drilled. The little guys, frankly, we haven’t seen any change in activity there yet either. They continue to be very active, and we’re bringing on a lot of incremental volumes for the median and smaller guys.
So to date, we have not seen a change in activity levels are high.
Your next question comes from the line of Theresa Chen with Barclays.
On frac 10, in terms of the time line, that seems to match with when you may be able to move over some of the Y-grade volumes coming off with the legacy loss processing plants onto your own system. Now that you’ve had these assets under your belt for some time, can you give us a sense of when do you expect that to ramp up higher in the cadence?
Yes. Sure. Theresa, it’s Matt. For frac train, whether it’s 9, 10 or GCF, we really see that our underlying G&P business and continued volume growth and just execution from our producer customers. We do have some contracts that roll off from time to time. Those are — most of those are T&F where it’d be more transportation and fractionation. So between now and 2025, we do have some of those. But the lion’s share of the need for frac Train 10 is just from underlying continued activity from our producers in our G&P business.
Got it. And then in terms of capital allocation and on the buybacks specifically, I understand that you don’t have a programmatic approach to this, and it’s more on an opportunistic basis. But just given the volatility in the dislocation in the market we saw during the first quarter, was there a reason why you didn’t want to utilize this tool kit this tool in your toolkit more?
Theresa, this is Jen. You saw us partially utilize the tool by buying a little bit more than $50 million in the first quarter. We also made a $1 billion acquisition of our remaining interest in Grand Prix during the quarter. So part of what we’re just trying to balance each and every quarter and then annually is just our spending requirements, whether that be a result of acquisition activity, like in the case of Q1 with the Grand Prix acquisition or other capital spending with the opportunities that we see in the market.
And we were able to step in, we believe, when given the opportunity in Q1 in a manner that we are very comfortable with.
Your next question comes from the line of Keith Stanley with Wolfe Research.
I wanted to start on the NGL and gas marketing for the quarter. I mean it looks just based on the percentage of margin like a record quarter for the company. So can you talk a little more to the types of activities? I guess did you fully anticipate the strength you saw this quarter as of the last call? Or did you see more opportunities in March? And then just overall expectations for the rest of the year, should we assume you kind of go back to normal on marketing? Or are you continuing to see opportunities to do better?
Yes. Sure. Keith, I’d say when we gave our guidance, part of that was already factored in. The guidance was given in February, we already had some of those seasonal opportunities, I’d say, and saw the strong LPG export market. We really had good performance across traditional kind of NGL marketing, gas marketing and LPG exports, part of which was known when we gave the guidance. So that was factored in to some extent. .
As we go forward, I’d say we do see kind of a more normalized level as we go throughout the year. That’s why Jen kind of pointed to a weaker Q2. So I think Q2 is going to be a little bit weaker. We don’t see those kind of outsized opportunities that we saw in but kind of more normalized as we move throughout the year.
Great. And then I guess just on the frac capacity. So I think you said in your prepared remarks, you were already at 800,000 a day recently, which I think is your capacity and then you reactivate GCF early next year.
So can you still grow frac volumes within your system over the balance of the year? Or are you at a point where you need to start offloading a little more already into the second half of the year?
Yes. We do have the ability to grow more. So we said we’re around 800. We can do low 800s of Y-grade at Bellevue. We also have our Lake Charles frac, which we can push some more volumes over there. And we do have ability to push volumes to other fracs. And in any given month, we’re unloading and offloading back and forth between different players in Bellevue for different reasons.
So we feel good about being able to handle all of our volumes between now and when GCF comes on the first part of next year, and then we’ll get even more relief when Train 9 comes on. But that gives us comfort that we’re going to have volumes for our GCF startup and when it comes on.
Your next question comes from the line of Colton Bean with TPH & Co.
Matt, I thought I heard you reference securing long lead items on two additional plants. So first, I wanted to verify the plural versus singular there. And then any comments on the planning horizon and how you see potential constraints shaping up across your Midland and Delaware footprint?
Sure. Yes, you did hear that correctly. Last call, we talked about long lead items for one plant. Now we’re securing long lead items for two plants. So I’d expect us to be greenlighting 1 or both of those plants relatively shortly. So we’re kind of signaling that. In terms of constraints, we have had really strong performance. We kind of gave those updates here where we are currently running.
We have enough capacity to handle our volumes from processing and transport and frac, but that is why we’re adding more capacity along kind of that whole value chain as we see continued growth through the rest of this year, we think it really sets us up for a strong 2024 as our volumes really ramp through the back half of the year, and we’ll have more capacity coming on in 2024.
For gathering and processing, I’d say it’s getting pretty tight on the processing side in both the Delaware and the Midland. The good thing about our plants and just the way our engineering teams have designed these is we have stretched above nameplate. So we’re putting in 275 million a day plants. So even when we’re at capacity, we can stretch up on these plants and go to, call it, 300 or so on most of these plants. So that gives us good flexibility and we’ve got gross capacity of almost 6 Bcf a day out there.
So if you can move that 10% it gives you a pretty good flex on the processing side. Then on the NGL side, we’ve been adding pumps on Grand Prix. That’s giving us some running room, but that’s why we’re adding Daytona as we see pretty good line of sight to needing that when that comes on, and then we’ve talked about the frac expansions. I’d say the other piece that we’re looking at. We have an expansion coming on in the export business this summer, one million barrels a month of propane loading. That is our next one.
We’re taking a hard look at and trying to determine for us what the right next project is for us. So we’re still kind of working through that with engineering operations and just timing of our overall volumes when we may need further export expansion.
Great. And just in terms of planning horizon, I think the latest dated plant we’ve got right now is Roadrunner II and kind of mid-’24. So should we think about these as being biased to the back half of ’24, maybe early ’25?
Yes, that’s probably reasonable. Yes.
Great. And then just back on the power supply issues you saw at Legacy II. I guess, one, can you expand on that? And then two, do you see any additional timing risk to ERCOT interconnects as you move toward completion on your other plants?
Yes. So we have Legacy I there already. So we’re able to — using the existing infrastructure. We had some extra capacity, which is why we’re running Legacy I is kind of in that it has the ability to be about 100 million a day. If you load up legacy One, we can load Legacy II to about $100 million or so a day. that should be — we should have all the electricity work done, the infrastructure done later this quarter.
So we’ll have full access to the full $275 million. That is 1 of our timing constraints as we’re putting in future plants. That tends to be 1 of the longer lead items to get put in place is the infrastructure. These plants that we’re putting in I mean the last 12 or so plants we put in have all been electric. And it just takes time to get all that situated as it’s a very large electric load.
Your next question comes from the line of Sunil Sibal with Seaport Global.
So when I look at processing ads in Permian, it seems like one to 1.2 Bcf per day of total processing adds you’re going through end I was curious if you know out of that, how much visibility you have on the residue gas take away just as a ballpark page?
Yes. So for the plants that we’re putting in, we are connecting to various residue outlets to make sure we have transport intra-basin to Waha that we can then get to market from there. So we’ll have connectivity within the Permian Basin for those plants. And then it really just goes to the broader basin is their takeaway out of the basin and what does that look like?
We have some compression expansions coming on. We have a long-haul pipes coming on mid next year, which should provide some relief. So it feels like when the long-haul pipe comes on next year, we’ll have some runway. But that’s why, as Bobby talked about, we’re beginning — we’ve begun work and discussions on Apex and what this next pipeline is after Matterhorn.
Got it. And my second question was a bit more longer term. Where do you see the balance sheet in terms of credit ratings over the medium to long term. I think some of your competitors kind of looked at shoring up ratings to mid-BBB. Is that the thought process with your team also.
Sunil, this is Jen. I think that ideally we’d like to be at least a mid-BBB company. And right now, we’re sitting one notch lower than that. I think that we have a very strong balance sheet right now. So we’re really comfortable with where our leverage ratio is today and the trajectory of that leverage ratio.
So ultimately, we believe that we’ll continue to execute as we have historically, which is execute across all dimensions of our business plan and then the ratings will be a result of that execution. But I would expect as we continue to manage through this year and into next year and our leverage ratio continues to improve, we’ll be looking to inquire about a potential upgrade with the agencies.
And your last question comes from the line of Neal Dingmann with Cap securities.
This is Jamison for Neal. Thank you for the questions here. I know we’ve touched on this a couple of times, but I just want to go back to the EBITDA guide for the year. I know you end marketing specifically. So I know you guys said marketing was, I guess, a little bit stronger than expected to some extent and that is going to be normalized for the rest of the year. And so given the fact that you also said that volume growth is looking strong for the remainder of the year as well.
Just trying to figure out, is there — does this mean there’s upside to the maintained EBITDA guide, given that 1Q strength in marketing? And I said that because I see a bullet in the slide deck that cite higher marketing and optimization, which I don’t think was there prior. So just trying to get a sense of, I guess, what implications are there?
I think as we think about balance of the year, there’s always the potential for additional upside in terms of higher commodity prices, if volumes exceed our expectation. If we see more optimization opportunities or if we’ve got commercial success beyond what we’ve already got baked into our forecast and that materializes this year. So we’ll have to see how the rest of the year plays out. But certainly, you’re hopefully hearing our excitement, not only that we have a really strong Q1 under our belt, but also that our outlook is as strong as it is. But we’ll have to see what happens with prices and ultimately when volumes materialize. And if we see more volumes than we expect our volumes ramp a little bit more slowly than we expect.
And I see no further questions at this time. I will now turn the call back over to Sanjay Lad.
Thanks, everyone that was on the call this morning, and we appreciate your interest in Targa Resources. The IR team will be available for any follow-up questions you may have. Thanks, and have a great day.
This concludes today’s conference call. Thank you for your participation. You may now disconnect. Have a good day.