Targa Resources Corp. (NYSE:TRGP) Q3 2024 Earnings Call Transcript

Targa Resources Corp. (NYSE:TRGP) Q3 2024 Earnings Call Transcript November 5, 2024

Targa Resources Corp. beats earnings expectations. Reported EPS is $1.75, expectations were $1.56.

Operator: Ladies and gentlemen, thank you for standing by. Welcome to Targa Resources Corp Third Quarter 2024 Earnings Webcast and Presentation. At this time, all participants are in a listen-only mode. After the speakers presentation there will be a question and answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. I would like now to turn the conference over to Tristan Richardson, Vice President, Investor Relations and Fundamentals. Please go ahead, sir.

Tristan Richardson: Thank you, Michelle. Good morning, and welcome to the third quarter 2024 earnings call for Targa Resources Corp. The third quarter earnings release, along with the third 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 investor presentation has also been posted to our website. Statements made during this call that might include Targa’s 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; Jen Kneale, President, Finance and Administration; and Will Byers, 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. I’ll now turn the call over to Matt.

Matt Meloy: Thanks, Tristan, and good morning to everyone. Before we get started, I want to welcome Tristan Richardson to Targa. Tristan will be leading our Investor Relations and Fundamentals functions after previously working in energy sell-side research for the last 13 years. With Tristan and Sanjay, we are in excellent position to continue to support our investors, analysts and potential investors with our best-in-class team. The third quarter was very strong on a number of fronts, record volumes, record adjusted EBITDA and continued execution across our footprint, which sets us up well for the balance of this year and provides a lot of momentum as we turn to 2025. Given our outperformance through the first 9 months of the year, we expect to beat the high end of our previously provided adjusted EBITDA range, which means more than $500 million of year-over-year growth, exceeding the midpoint of our initially provided guidance range for 2024 by more than $250 million.

Over the past several years, we have deliberately taken steps to successfully position Targa across volatile markets, and we are benefiting from those steps. We have largely removed exposure to downside commodity prices, with 90% of our margin now fee-based or supported by fee floor contracts. We have continued to invest in growth capital and attractive opportunities with best-in-class customers with a focus on deals that allow us to move volumes all the way through our integrated system. We have significantly strengthened our balance sheet, and are now a strong investment-grade credit across all 3 agencies. We have returned an increasing amount of capital to our shareholders while maintaining financial flexibility. We believe that these important steps enhance our abilities to generate attractive returns for our shareholders across commodity price cycles.

Our excitement around Targa’s short-, medium- and long-term outlook begins with our Permian position, and there are a lot of good things going on there. Our new plants have continued to come online, essentially full and given our expectation that our plans in progress will do the same, today, we announced that we are moving forward with our next 2 new Permian plants in response to higher anticipated growth we are seeing and to ensure we keep pace with our producers. We are continuing to enhance our sour gas treating position in the Delaware Basin with additional investments in front-end treating and AGI infrastructure. Our new 800 million cubic feet per day sour gas treater and injection well comes online in early 2025 at our Bull Moose complex, which, along with our current 6 active acid gas injection wells, will increase our treating capacity to over 2.3 billion cubic feet per day in the Delaware.

Additionally, we are utilizing and enhancing existing infrastructure to capture and sequester CO2 in the Permian, and we’ll be accruing some 45Q tax credits in the fourth quarter of this year and increasing over time. Our Permian growth drives increasing volumes through our downstream assets. Daytona was much needed when it came online. Train 9 has been full since it came online. And Train 10 and GCF are much needed and will be highly utilized. Our premier Permian supply aggregation position, coupled with our integrated NGL system, positions us nicely to continue to generate strong returns on our invested capital and be able to continue to return increasing capital to our shareholders over time. Before I turn the call over to Jen to discuss operations and capital allocation 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 service and reliability to our customers.

The growth we are experiencing requires a lot of coordination across our organization, and we are proud of our employees.

Jen Kneale: Thanks, Matt. Good morning, everyone. Let’s talk about the strength of our operational results in more detail. Starting in the Permian, our natural gas inlet volumes averaged a record 6 billion cubic feet per day during the third quarter, a 5% increase when compared to the second quarter. Versus last year, our Permian volumes were up 18%, over 900 million cubic feet per day or more than 3 full plants, driving record NGL transportation and fractionation volumes. Our G&P volume growth has led to an acceleration of timing of our processing plants, including the two that we announced today. In Permian Midland, our new Greenwood 2 plant commenced operations in early October, essentially full. Our next Midland plant, Pembrook 2 and East Pembrook, will be much needed and remain on track to begin operations in the fourth quarter of 2025 and second quarter of 2026.

The new Midland plant that we announced this morning, East Driver, is expected to begin operations in the third quarter of 2026. In Permian Delaware, we are continuing to benefit from increasing volumes. Our next Delaware plant, Bonus and Bonus 2, will be much needed and remain on track to begin operations in the first quarter of 2025 and the first quarter of 2026. Our next new Delaware plant, Falcon 2, is expected to begin operations in the second quarter of 2026. Shifting to our Logistics and Transportation segment. Targa’s NGL pipeline transportation volumes averaged a record 829,000 barrels per day, and fractionation volumes averaged a record 954,000 barrels per day during the third quarter. Our NGL transportation and fractionation volumes increased 6% sequentially as we benefited from increased supply from our Permian G&P systems.

Given the anticipated growth in our Permian G&P business and corresponding plant additions, our outlook for NGL supply growth is robust, and our downstream system expansions are very much needed to handle growth from our systems. Our next fractionator in Mont Belvieu, Train 11, remains on track for the third quarter of 2026. In our LPG export business at Galena Park, our loadings averaged 12.4 million barrels per month during the third quarter despite our volumes being impacted by a required 10-year inspection that reduced our loading capability from mid-June through late July. We see continued strength in global demand for U.S.-sourced LPGs, and we remain on track to complete our next expansion, which will increase our loading capacity an incremental 650,000 barrels per month in the second half of 2025.

Turning to capital allocation. Our priorities remain the same, which are to maintain a strong investment-grade balance sheet, to continue to invest in high-returning integrated projects and to return an increasing amount of capital to our shareholders across cycles, and we are delivering on those priorities. We are returning meaningful increases in capital year-over-year to our investors. We opportunistically repurchased $168 million of common shares during the third quarter. Through 3 quarters, we have repurchased nearly $650 million of common shares at a weighted average price of $121.50, a substantial increase over $347 million of share repurchases for full year 2023. Our year-to-date repurchase activity means we are in a position to return 40% to 50% of our adjusted cash flow from operations to shareholders this year.

This is an acceleration versus previous expectations, driven by the outperformance of the business and our strengthening outlook. We are pleased to announce this morning that we expect to recommend to our board an increase to the 2025 annual common dividend to $4 per share, a 33% increase over the 2024 dividend level. This provides our shareholders with a meaningful year-over-year increase while continuing to maintain our flexibility. Beyond 2025, we expect to be in a position to continue to provide meaningful annual increases to our common dividend per share. We believe that we offer a compelling value proposition for our shareholders and potential shareholders. Growing EBITDA, a growing common dividend per share, reducing share count and excellent short-, medium- and long-term outlooks.

We also recently published our 2023 Sustainability Report. Our report reflects that we take our responsibilities of being an operator of critical natural gas and NGL infrastructure seriously and celebrates the continued hard work of our employees. We look forward to your feedback. I will now turn the call over to Will to discuss our third quarter financial results. Will?

Will Byers: Thanks, Jen. Targa’s reported adjusted EBITDA for the third quarter was a record $1.07 billion, a 9% increase over the second quarter. The sequential increase was attributable to higher Permian volumes, which resulted in higher system volumes across our integrated NGL business and to continued natural gas and NGL optimization opportunities in our marketing business. The adjusted operating margin for our Gathering and Processing segment set another quarterly record of $788 million as a result of the strength of volume growth supported by our fee and fee floor contracts. Our Logistics and Transportation segment also set another quarterly record with adjusted operating margin of $717 million, backed by record NGL transportation and fractionation throughput.

As Matt mentioned, we now estimate full year 2024 adjusted EBITDA to be above the top end of our previously disclosed $3.95 billion to $4.05 billion range. We anticipate a strong finish to 2024 as our recently completed expansions and capacity additions across Permian G&P and NGL transportation and fractionation support continued volume growth. For the third quarter, our net maintenance capital spending was approximately $60 million. Our current year estimate for net maintenance capital spending remains $225 million. Our net growth capital spending was approximately $700 million for the quarter. Our net growth capital spending for 2024 will depend on our ability to order certain long lead time items before year-end. Among other factors, we currently expect spending to modestly exceed $2.7 billion.

The acceleration of spending on infrastructure to handle additional volume growth is expected to increase our net growth capital spending for 2025 and contribute to higher adjusted EBITDA when the incremental plants we announced today are in service in 2026. We continue to expect a meaningful inflection in 2025 free cash flow generation relative to 2024, and we’ll provide additional details on 2025 growth capital spending in February once we are fully through our planning process. In August, we extended the maturity of our $600 million accounts receivable securitization facility to August 2025. And we successfully completed a $1 billion note offering of 5.5% coupon senior notes due 2035. The notes offering allowed us to enhance our liquidity position by reducing borrowings under our commercial paper note program, a portion of which was incurred to repay the remaining $500 million outstanding under our prior $1.5 billion unsecured term loan facility which was terminated in May 2024.

At the end of the third quarter, we had approximately $1.9 billion of available liquidity. And our net consolidated leverage ratio was approximately 3.6 times, well within our long-term leverage ratio target range of 3 times to 4 times. Moody’s upgraded target to Baa2 in early October, reflective of the progress we have made to date and our outlook for the future. We have now achieved upgrades from all 3 agencies in 2024 and have mid BBB ratings and a stable outlook at each of the 3 rating agencies. Maintaining a strong investment-grade balance sheet remains a priority at Targa. Having been at Targa for a little over 3 months now, I am humbled every day by the dedication and tremendous work ethic of the employees of Targa. I’m grateful for the opportunity to be a part of this exceptional team.

And with that, I will turn the call back over to Tristan.

Tristan Richardson : Thank you, Will. For the Q&A session, we ask that you limit yourself to 1 question and 1 follow-up and reenter the queue if you have additional questions. Michelle, please open the line for Q&A.

Q&A Session

Operator: Thank you. [Operator Instructions] And our first question will come from Theresa Chen with Barclays. Your line is now open.

Theresa Chen: Congratulations on the fundamental growth and the accelerated pace of growth over the near term. I was curious, as we look to 2025 CapEx and general capital allocation plans, can you provide more color on how long do you expect this accelerated growth to endure? And B, how high could CapEx go to in 2025?

Matt Meloy: Yes. No, we’re excited about the results today. We’re really excited just about the overall performance we’ve seen so far this year and it’s just translating into higher EBITDA growth, higher volumes across our G&P footprint in the downstream. We think that really sets us up well as we look into 2025. In terms of capital spending, as we look to 2025, we’ve certainly seen an acceleration on the Gathering and Processing side of things. It’s resulted in more field level capital for this year, and it’s likely to continue into next year, additional pipelines, additional compression, but it’s also resulted in acceleration of our plant timing. Earlier in this year, we had a estimate of when we’re going to be putting plants on for the next 12, 24, 36 months, and that has accelerated just as our volumes have moved significantly higher.

Third quarter was up $900 million a day versus third quarter of last year. We were expecting growth this year, but not that level of growth. So we think that really just puts us in a good position as we go forward. So accelerating Falcon 2 plant and East Driver plant, that’s going to drive more capital in 2025. We don’t have a number we’re going to give you yet. We’re still going through our planning process. We plan to give you more details of what our G&P spending is, cadence of any additional plants and our plant timing in February. And on the downstream side, what ultimately that means when those plants come on, generate more NGLs, what that’s going to mean for our Downstream business. So that’s kind of the planning we’re going through now, and we plan to give you more color on that in February.

Theresa Chen: And looking at the downstream throughput across your doc, clearly seeing an uptick following a partial downtime in third quarter and fourth quarter looks extremely robust. Can you just provide a forward outlook on how you expect this to trend? How much of it at this point do you think it’s going to be seasonal versus just the relentless supply push of molecules across your docs through the integrated NGL value chain?

Scott Pryor: Theresa, this is Scott. First off, yes, we had a nice quarter during the third quarter. It was a nice rebound from what we had in the second quarter of this year. So a lot. Even though it was impacted, the second quarter was impacted by the vessel inspection that we had and that lingered into the month of July. So when we look at the back half of third quarter, we certainly had significant increase over the months. And we would see that continuing as we move into the fourth quarter now that we’ve got the full complement of all of our refrigeration capacity. So I would anticipate during the fourth quarter that the volumes would be very complementary, if not exceed what we saw in the third quarter. We continue to benefit from a variety of sources of demand, both of it on the propane side as well as on the butane side.

And we’re utilizing really not only our VLGC docs, but we’re using some of our smaller docs that complement MGCs and LGCs and moving to markets that are closer than, say, the Far East. So a lot of that benefited as we looked across the third quarter then into the fourth quarter. Moving into 2025, I think it’s going to be very much the same story. We benefited as an industry with a number of vessels that have come online, both in ’24 and now in ’25. We’ll continue to see more vessels delivered to the marketplace on both the VLGC side as well as the MGC side. So I think it’s just setting itself up to where right now, freight is relatively low, and it puts us in a position to where it’s easy to fund supply from the U.S. into the markets across the world.

Operator: And our next question comes from Jeremy Tonet with JPMorgan. Your line is open.

Jeremy Tonet: So out of the producer activity, I think the producers in the basin, I think we’ve heard some mixed messages with regards to, I think, the integrated versus large independents versus smaller. And just wondering if you could share a bit more on your conversations with producer customers here and particularly how your New Mexico position, I guess, differentiates you from others in the basin?

Matt Meloy: Yes. Jeremy, this is Matt. I’ll start, and then Pat, if you want to add on. The discussions we’re having with producers, it is a mix. The small, mid, large cap, that’s — we have a portfolio of customers, and it’s not all the same. But what we are seeing generally is more growth on the gas side relative to their expectations. So we haven’t necessarily seen more activity, but we have just seen the wells be more productive. And whether that’s lower declines, increasing GORs, higher IPs, we’re just seeing more volumes. We continue to be surprised this year to the upside on gas volumes. And as we look out, we’re sorting through our producer forecast right now, what that’s going to mean for ’25, ’26 growth. We think there’s going to be significant growth.

Kind of where exactly that falls out is kind of what we’re working through right now. But I think we remain bullish on the outlook for natural gas growth across our footprint. As you look to New Mexico, we’ve had a really good footprint in the Delaware for some time. But I would say when we acquired the Lucid assets in 2022, to us, they had the best Delaware footprint. And so that fit nicely into our systems that we had. We were able to integrate those systems. And I think when you look at just the rigs, where the activity is, we’re kind of have a best-in-class system across the Delaware with a complement of Lucid. So I think we’re in a good position to capture the strong activity in the New Mexico area.

Patrick McDonie: No, I was going to say, the only thing I’d add is, Matt’s right. With the Lucid acquisition, it was definitely a step-up for us in the Delaware. And the steps we’ve taken to integrate that system into our other Delaware systems and the sour gas infrastructure that we’ve built out have led to a lot of commercial success. The Delaware Basin is growing rapidly. There’s a lot of gas over there, and we’re positioned very well to take advantage of that.

Jeremy Tonet: And then kind of continuing here as it relates to the gas picture and gas egress from the basin. We have a couple of projects in motion at this point, you’re part of 1 of them. How do you think about, I guess, the picture for future gas egress needs in the basin, when do you think that could materialize next? And what do you think Targa’s involvement could be here?

Robert Muraro: This is Bobby. I think we announced our partnership with Blackcomb a little bit ago, we’re excited about that project moving forward and it’s going well. I think we said before and we’ll continue to say, we want to see as much egress out of the basin happen as possible. We know there are a lot of other pipes that are in the works right now. We were thinking about ’28 when we were working on the ’26 pipe with Blackcomb. So we continue to work on what is needed going forward. With what we’re seeing in gas production coming out of the wells, we expect there to be on the margin faster cadence for the need on gas pipe. So if someone else gets another gas pipe done “today,” we think that’s great for the basin, and we would be excited to see it happen.

Jeremy Tonet: And if I could just round that out a little bit more. In basin consumption growth, industrial demand growth or even maybe data centers down the road, do you see that, I guess, impacting the picture there?

Robert Muraro: This is Bobby again. I think we know there are a lot of people talking about it right now. We are in conversations with customers that are in conversations with all of those consumption points. So what gets built, when it gets built, what actually gets permitted and put under construction, I think it’s yet to be seen. But there is a lot of action and a lot of conversation going on right now across the basin around those topics.

Operator: And our next question comes from Michael Blum with Wells Fargo. Your line is open.

Michael Blum: I wanted to ask about the sort of the long-term trend here in growth CapEx. Obviously, you’re trending higher here in the near term. I noticed you still have that same slide, which shows like a typical year at $1.7 billion. So is that still kind of normal year normalized run rate? Or is that number moving higher as producers, these numbers sort of exceed your expectations?

Jen Kneale: Michael, this is Jen. I think that when we put out that illustrative framework, we said that a good multiyear average for growth capital spending in a high single-digit Permian Basin growth environment would be about $1.7 billion. And we even caveated on the slide that if we were going to see growth substantially higher from there, we would expect CapEx to move higher as well. All very much core growth capital spending, the need for more gathering lines, more compression, potentially requiring the acceleration of major growth capital projects like plants and then downstream infrastructure. So the framework still holds for an environment where you’re seeing high single-digit growth. As Matt said, so far, we’ve experienced 18% growth Permian this quarter relative to the third quarter of last year.

For the 9 months of this year, we’re up 14% relative to the 9 months of last year. So clearly, we are in a more robust environment, and that’s resulting in us needing to accelerate some spending for that core infrastructure, additional gathering line compression, plant capital to make sure that we’re in a position to handle the increasing growth for our producers. I think Pat also mentioned that we’ve enjoyed a lot of commercial success this year, and that’s resulting in us needing to accelerate infrastructure spend on the G&P side for 2026, when we expect growth to continue to increase versus previous expectations when we provided that in February. So I think absolutely, it still holds together. It ultimately just depends what your view is of Permian growth.

And, in particular, Permian growth on Targa’s systems, where we are seeing more growth than others. And we very consistently have said that that’s the case since we put out that framework in February.

Michael Blum: Okay. Makes sense. I then wanted to just ask about buybacks. Would you say that you’re now more of an almost ratable type of buyback approach? Or is it still very much opportunistic and price-sensitive? And if it’s the latter, how do you think about the pace of buybacks as the stock price just continues to move higher?

Jen Kneale: I would say that we are very much continuing to be opportunistic around share repurchases. And that’s how we expect to continue to think about it going forward. Our priorities around capital allocation are unchanged. I think that what we’ve seen this year is a very strong 2024 is resulting in a lot more momentum when we think about ’25, ’26, ’27, ’28 and beyond that. We have a lot of conviction in what we have going on here at Targa for the short, medium and long term. And what you’re seeing is us opportunistically execute around repurchases based on that conviction. And so I think you should continue to expect repurchases going forward, but they will continue to be opportunistic. We consider a number of different factors in terms of what our daily and quarterly activity looks like.

So you should certainly expect some continued variability moving forward, but we do believe it’s a very important tool for us to be able to use to return more capital to our shareholders as we move forward through time.

Operator: And the next question comes from Keith Stanley with Wolfe Research. Your line is open.

Keith Stanley: It seems like a pretty meaningful change in your volume outlook, even versus 3 months ago. I mean, you just updated the 2024 and ’25 EBITDA and CapEx. So with that in mind, I wanted to just check back in on plans for NGL pipeline spending. Do you envision that potentially now being accelerated into 2025 at this point?

Scott Pryor: Keith — oh, sorry.

Tristan Richardson: No, sorry, I’ll just say — Scott, go ahead.

Scott Pryor: Okay. Keith, this is Scott. So certainly, when we look at our transportation legs, we looked at the third quarter, we averaged to 784,000 — excuse me, 829,000 barrels a day of transportation. We got a partial benefit of Daytona coming online in the third quarter. Obviously, in the fourth quarter, we’ll have the full complement of our West leg of Grand Prix and then Daytona, and then that marries up with our 30-inch pipe that moves into Belvieu that gets contributions from the North Texas area as well as Oklahoma. So we’ve got some operating leverage today, certainly on the West leg when you think about those 2 24-inch pipes, and then we’ve got some operating leverage on the 30-inch pipe. The other thing that we’ve done in order to really take care of what our growing capacities are relative to what’s going on the upstream side is we’ve entered into some third-party agreements that allows us the opportunity to really push out some capital benefit from the timing of when we would need to basically loop our 30-inch line.

So those agreements, along with the operating leverage we have today, really gives us the benefit of time to evaluate what the volume rents look like over time. Those agreements that we’ve done really are in cadence. They ramp up in volume capacities that match up very well with kind of our near-term plant growth. But obviously, as we continue to add plants on the upstream side, eventually, we’ll be in a position where we’ll have to loop that 30-inch pipe. We will continue to evaluate that as we move into ’25 with our budget process, and we’re looking at CapEx. So I think we’ve got the benefit of time on our side right now with those agreements and the current leverage that we have.

Keith Stanley: The second question, the marketing was really strong in Q3. Would you attribute that more to spot LPG exports? Or is it optimization around weak Permian gas again? And on exports, it seems like you’re constructive on pricing, but any sense of volumes you can share that might be able to take advantage of the strong ARPS?

Jen Kneale: Keith, this is Jen. I’ll start. I’d say that it’s been a strong year of marketing for us across all of NGL, natural gas and export marketing. We generally don’t factor that into our guidance. So when you think about some of the factors that have contributed to our outperformance this year, certainly having a strong marketing year has been one of those variables. I think that as we think — as we look forward, we expect that given the vastness of our footprint, we would be able to continue to identify strong marketing opportunities. But ultimately, it’s really a combination of a lot of factors. And it’s driven by the fact that we are moving so much volume across both our gas and NGL systems. That’s really affording us some unique marketing opportunities as we move forward through time.

Scott Pryor: And Keith, this is Scott. Just as a follow-up to what we said earlier. The volumes in the third quarter were impacted a little bit due to our vessel inspection. But as we move into the fourth quarter, we would expect that to improve. Again, we benefited on the export side by being able to squeeze other cargoes in, again, the smaller size type vessels because we were playing a little bit of catch-up with the downtime that we had with the vessel inspection in the third quarter. So we’ll see if the ARPS continue to be strong, and we’ll look for opportunities to optimize around the system.

Operator: And our next question comes from Jean Salisbury with Bank of America. Your line is open.

Jean Salisbury: I believe that you’ve said before that most of your producer base has gas egress and hasn’t been backed up the last 2 quarters, which I think has really showed in your volume results today. Does that mean that as Matterhorn ramps through the end of the year, you wouldn’t really expect an outsized quarter-on-quarter step-up in volumes kind of over the next quarter or 2 as gas gets unlocked from the basin?

Matt Meloy: Yes, I’ll start. We have not seen, I would say, across our producers, really Midland and Delaware, any negative volume impact from not having gas takeaway. We try and work with our customers to make sure that Targa’s handling and moving those volumes on behalf of our producers. We have enough firm transport, intra and out of the basin to be able to move those volumes. And then producers on our system that have their own taking kind positions typically have enough transport to get those out. And so we work with them to make sure we can move those volumes. So I wouldn’t say that will be a factor in kind of quarter-to-quarter growth. But as you look at just our volume growth across this year, in the last 2 quarters, we’ve been about 300 million a day, give or take, of volume growth in the second and third quarter.

That’s higher than normal. I don’t know that I’d plug that in for — plug in another 300 for Q4. I think we’re going to have some growth, but it’s likely not going to be in a straight line as you kind of move forward. I think we see strong growth going forward, but Q4 is likely to be a bit muted compared to the strength we saw in the second and third quarter.

Jen Kneale: Just to provide a little bit more visibility in the fourth quarter, we do also have a lower margin contract that’s rolling over on the G&P side. So that will also reduce volumes quarter-over-quarter. So again, I think that speaks to us not being able to sustain the 300 million a day of growth that we’ve seen in the last couple of quarters, although we are still performing exceptionally well and are still seeing a lot of volumes come to us. That contractor all over will impact the fourth quarter.

Jean Salisbury: And then it seems like you should have the volume to fill your LPG expansion basically like immediately after it comes online next year. But there’s obviously a lot of LPG export capacity coming online at the same time. Beyond that existing expansion, would you consider deploying the strategy that you’ve discussed of signing up for third-party LPG capacity kind of like what you do for pipelines to defer your own spend from here? Or do you see it as more strategic and value to have your own export capacity?

Matt Meloy: Yes. I think what we’re trying to do the easy debottlenecks, which are really economic for us to just handle kind of the incremental volume growth we see across our footprint. But as this next one we have coming on mid next year, we are right now looking at kind of a larger step up in our LPG exports and bringing on capacity. Others are adding some as well. We’re just seeing a lot of NGL volume growth and so are others. So I think it’s all going to be needed. So we’re currently evaluating right now, the timing and the size of our next LPG export expansion. It’s likely going to include pipeline and additional refrigeration. Yes, both of those together is probably around $350 million or so for those 2 pieces. And so that’s part of our planning process.

And as we think about capital for ’25 and ’26, when we’re going to need that, some of that capital end up in the back half of ’25? Or is that a ’26, ’27, ’28 kind of spending? That’s what we’re sorting through right now. But I do think it’s needed. I don’t see us in any real meaningful or term way contracting with others to bridge for us. I think we’ll handle our own export across our docs on our own volumes.

Scott Pryor: Yes. And just to complement that a little bit, Jean, this is Scott. I would say that the primary pieces that Matt talked about on the — excuse me, on the refrigeration side and on the pipeline side, as you said, kind of in that $350 million range. We — and then before that. And even after that, we’ll look for ways to kind of debottleneck even around that system by just an improved piping, both at our Belvieu facility as well as at our Galena Park facility. We’re an aggregator of supply in Belvieu. So as our volumes start ramping up at that is coming off of our system, puts us in a position to prioritize that volume as opposed to volumes that we could aggregate in and around the Belvieu marketplace. So future expansions, we would look to take care of our volumes, but we would also put ourselves in a position to where we might have some capacity that we could optimize around that as well.

Operator: And our next question comes from John Mackay with Goldman Sachs. Your line is open.

John Mackay: You guys have had this sour gas footprint for a while now, but you spend a little more time talking about it on this call. So I’d just be curious to hear kind of how much of that pocket of the business could grow from here? What CapEx associated with that could look like? Because it’s a little different than a typical kind of G&P build-out. And maybe just next milestones to watch there?

Matt Meloy: Yes, sure. We have been operating sour gas infrastructure kind of through Targa’s history and even going back to the Dynegy days. So we have decades of experience of handling sour gas out there. We’ve seen the Delaware side continue to get more and more sour. So years ago, we really ramped up our spending to be able to handle more sour volumes out there. And that’s really both H2S and CO2. So we mentioned in the call today, we have an 800 million a day treater coming online at our Bull Moose complex. We have additional wells being drilled in the permitting phase to continue to hand more and more volumes as the Delaware gets more and more sour over time. So we think that really does give us an advantage as we look out for growth over the short, medium and longer term.

It’s a little bit more tricky to handle the sour volumes. It’s a little more difficult than just having handling sweet volumes. And so when it’s harder, it gives us just better opportunity to work with our producers to handle those volumes. So we see that trend continuing. And I think that leads to some of our optimism about our longer-term growth rate out in the Delaware.

Robert Muraro: And this is Bobby. If you think about all the plants we’ve announced over the last several years on the eastern side of the Delaware Basin, even though we don’t talk about it, all those plants are sour plans. So we don’t talk about that. But if you think about Midway or if you think about Wildcat or if you think about [ Bolus ] or any of those plants, all those are sour plants. We just don’t label in that way or we haven’t historically as brightly as we do now just because that has obviously become front and center of one of the talking points in the industry.

John Mackay: Maybe just actually a quick follow-up to that then. You talked about getting some 45Q credits in this quarter. We’re getting close — you guys are getting closer to kind of a broader cash tax payment requirement over the next couple of years. Could the 45Qs get to a meaningful size where we’re talking about some real offsets there? Or is this kind of nice to have, but a little more on the margin in the grand scheme?

Robert Muraro: This is Bobby. So I think when you talk about grand scheme, I think it’s on the margin, but it is also a nice to have. So when you think about all of that — all of those assets I just talked about on the eastern side of the Delaware Basin where we are putting in our infrastructure that gathers that sour gas, strips out the CO2 and H2S and injects it. We modified those systems a little bit and then we are able to get 45Q. So it is a very nice complement to that business and very efficient capital to spend in order to get that 45Q. So it turns into something that we don’t have to do a whole lot more and be able to capture the 45Q. We continue to develop the CCUS business where it’s not required to inject and that’s in our forecast over time. But at the end of the day, when you talk about grand scheme of Targa, it is not huge relative to everything else we have going on.

Jen Kneale: And so just to finish that out, John, that means that from our perspective, it doesn’t meaningfully change our outlook for cash taxes. As Bobby said, it’s a nice to have, but there’s really no change to our current expectation that will be subject to the ATM in 2026 and then a full cash taxpayer in 2027 when we’ve worked our way through our NOL. And that’s all inclusive of our full business operations, including the opportunity set around CCUS.

Operator: And our next question comes from Manav Gupta with UBS. Your line is open.

Manav Gupta: First of all, big congratulations to Tristan. Every time a sell-side analyst is able to do a jailbreak, it feels very nice for the rest of us. There is hope for us.

Tristan Richardson : Well, thank you for that.

Manav Gupta: My quick question, just one of them, is can you provide us more details around Falcon 2 or East Driver plants, why decision to move ahead with them? Anything you can give us on the economics or the build multiple?

Matt Meloy: Sure. I’d say the economics and build multiple is really the same that we’ve articulated previously. We’ve kind of pointed to around 5.5 times as our organic build multiple. I don’t see these being materially different from that. So I think it just puts us in position to continue to invest either for our producers and execute on our core business, gathering and processing, and then moving the NGLs through our downstream infrastructure. And the timing of those, as I mentioned earlier, we’re just seeing more volumes across both the Delaware and the Midland side of the Permian. And so that’s led us to announce those kind of sooner than we were expecting. If you kind of go back to the beginning of the year, we were not anticipating announcing these plants right now and starting this work as soon as we are. But the volume upside has allowed us to accelerate these plants. And then we evaluate the timing of the next plants.

Robert Muraro: And this is Bobby. As Jen mentioned earlier in the call, Greenwood 2 coming up, highly utilized. At the end of the day, we keep trying to get a plant ahead. We keep trying to create space to be able to overhauls and maintenance and everything else. And this is a continued effort to try to get ahead so we can do all the things we need to do within our system and service our producers at the same time.

Operator: And our next question comes from Neal Dingmann with Truist. Your line is open.

Neal Dingmann: Another nice quarter. Welcome, Tristan. My first question is just on your Permian Basin activity outlook. Specifically, I see on Slide 8, you mentioned your associated gas forecast that looks very favorable. I’m just wondering, I’d love to hear sort of what type of rig activity do you are and maybe not the oil price you’re assuming around that associated gas forecast?

Patrick McDonie: Yes. This is Pat. When you look across the Permian right now, one out of every three rigs is running on Targa acreage. So activity level on our acreage footprint is very robust. And obviously, that acreage position that we have tied up is pretty significant. Matt alluded to it earlier on one of the other questions is — it’s producer-specific, right? We are seeing a lot of activity from different sized producers and new formations being explored and developed, some of those very gassy, which leads to gas growth across both Midland and Delaware sides of the basin. Unfortunately, we’ve had commercial success, additional new commercial success to tie up those plays. So it’s the historical stuff we’ve always seen with the large acreage dedications and the activity and the commitment of very high-grade producers.

And then some new stuff that’s getting developed that we’ve been successful in. So when we look across the next 5 years, especially in the next 24 to 36 months, we see a lot of gas growth on our systems and a lot of activity on our systems.

Neal Dingmann: Yes, that makes a little sense. And then my second question, just on your future capital spend. Specifically, just wondering, would you all suggest there’s any possible or potential incredible assets out there that could delay your meaningful 2025 free cash inflection? Or does that novel upside or upcoming inflection appear to be relatively certain?

Matt Meloy: I think when you just look at just our overall EBITDA growth we’re going to have in ’25 and with — haven’t given a firm number for capital yet for ’25, but I think we’re comfortable saying we’re going to have a significant amount of free cash flow in 2025. Where exactly that shakes out is kind of what we’re working through in our planning process, as we’ve talked about. Delaying or deferring that, I guess you’re implying kind of M&A. We continue to look at assets, bolt-ons in and around our systems. We’ve continued to look really since the loose of acquisition at assets. But I think just for us, the bar continues to be very high for us. So we’ll continue to evaluate. If there’s something we can tuck in that looks really nice and has good value for Targa shareholders, we’ll look at it.

it’s just the bar is going to be pretty high. We have a lot of growth on our G&P footprint and our downstream footprint. Our first priority is to make sure we execute on what we have organically in front of us. That’s just going to continue to be our priority.

Neal Dingmann: Yes. The growth is notable.

Operator: And our next question comes from A.J. O’Donnell with TPH. Your line is open.

A.J. O’Donnell: Just one for me, and I kind of just wanted to go on a clarifying question to something that Jean brought up. Looking at Q4 volumes and our potential for volume growth and now that Matterhorn is in line. I’m curious if you guys have seen a jump in production from your customers with the new pipe being online? Or if some of the flows that we’re seeing online or with that pipe right now is just gas moving around the basin?

Matt Meloy: Yes, sure. No, from our customers, we — I would say I have heard of some customers that were not producing because they didn’t have — they either didn’t like the Waha price or didn’t have takeaway. But customers on our system, they were flowing and producing. So I think basin-wide, perhaps there is some of that. But for our customers, for — I think the most part, they were producing and had takeaway.

A.J. O’Donnell: Absolutely. Yes.

Matt Meloy: So I think what’s happening now is volumes kind of coming off, others moving on Matterhorn and it’s just trying to find its way out of the basin. But with Matterhorn up and other pipelines online, there should be sufficient capacity at least for a while to handle those volumes. What you’re seeing now is some maintenance on some pipes and some other disruptions on existing pipes, which is why our Waha has been kind of flat to negative here recently.

Operator: And our next question comes from Sunil Sibal with Seaport Global. Your line is open.

Sunil Sibal: So I wanted to start off on the NGL pipeline segment. Seems like ethane prices have been weak lately. So I was curious what kind of ethane recovery trends you are seeing on your systems? And then the Daytona kind of contributing partly for the third quarter, how should we think about volumes on the Daytona system, especially any switchovers from third-party processing plants also?

Scott Pryor: This is Scott. First off, Daytona coming online gives us the ability to obviously flow on both our Grand Prix West system as well as Daytona. So it gives us some operating efficiency around just being able to split volumes between those 2 pipes and gives us a lot of operating leverage, as I said earlier, moving into our 30-inch pipe. When it comes to ethane, certainly, ethane prices sitting around $0.18. There may be some outlying areas that would be looking at rejection type economics. But when you look at the Waha area where gas prices are, I think pretty much most of the industry is in full recovery wherever they can, predominantly in the Permian Basin. And for us, we stay pretty much in recovery mode all the time just so that we can feed our system on all of our integrated platform.

So again, I think some of the outlying areas outside of the Permian will probably be in rejection mode just based upon where prices are. But for us, it’s pretty much full tilt for us.

Sunil Sibal: And then in the Badlands system, it seems like you had a pretty sizable uptick on the crude volumes. I was curious, is that something we can expect to continue or any onetime items there?

Patrick McDonie: Yes. This is Pat. We had an uptick in our activity level. We had some producers that have been waiting on permits and another producer, frankly, that hasn’t been real active over the past let’s say, 3 or 4 years that, one, the activity level from that producer upticked. And secondly, the permits were granted and the wells were drilled. So we got a really nice uptick in our crude oil volumes. And our base level continues. So we expect good activity. I wouldn’t say continued robust growth, but good activity level going forward on the system.

Operator: I show no further questions at this time. I would now like to turn the call back over to Tristan Richardson for closing remarks.

Tristan Richardson: Great. Thanks, Michelle. Thank you to everyone for joining the call this morning, and we appreciate your interest in Targa Resources.

Operator: This does conclude today’s conference call. Thank you for participating. You may now disconnect.