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Good day and thank you for standing by. Welcome to the Targa Resources Corp. Fourth Quarter 2023 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 now like to hand the conference over to your speaker today, Sanjay Lad, Vice President of Finance and Investor Relations. Please go ahead.

Thanks, Shannon. Good morning and welcome to the fourth quarter 2023 earnings call for Targa Resources Corp. The fourth quarter earnings release, along with the fourth quarter earnings supplement presentation for Targa 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; and Jen Kneale, Chief Financial Officer. Additionally, we'll have the following senior management team members 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 will now turn the call over to Matt.

Thanks, Sanjay, and good morning. 2023 was another record year for Targa. And I would like to recognize and thank our employees for their focus, dedication and execution throughout the year. Some of our highlights for 2023 include record safety performance; record Gathering and Processing volumes in the Permian; record volumes across our logistics and transportation assets; record adjusted EBITDA of $3.53 billion, a 22% increase over 2022, while also reducing our share count; major projects came online on time, on budget and have been highly utilized since start-up; ended the year with 90% of our G&P volumes fee-based or with fee floor; positive outlook to our current investment-grade ratings with each of the three agencies and the completion of two successful notes offerings; and higher year-over-year return of capital to our shareholders through both an increased common dividend and record common share repurchases. Our performance was particularly strong given Waha natural gas and NGL prices were about 64% and 34% lower year-over-year. And we benefited from margin from fee floors in our Gathering and Processing business across 10 of 12 months, demonstrating our business is more insulated to downside -- to downward commodity prices than ever before. We also exited 2023 with a lot of volume momentum in the Permian. Our December reported inlet averaged 5.5 billion cubic feet per day, a 450 million cubic feet per day improvement from our third quarter average. While our volume ramp materialized later than we forecasted for 2023, we are pleased that we ended the year with December actuals in line with our original guidance expectations for the Permian, providing us with strong momentum in 2024. We expect another year of record financial and operational metrics with full year adjusted EBITDA estimated to be between $3.7 billion and $3.9 billion for 2024. The significant year-over-year increase in adjusted EBITDA is primarily driven by higher expected Permian Gathering and Processing volumes and higher expected NGL transport fractionation and export volumes. Consensus growth expectations for Permian-associated gas in 2024 is about 9%. And given our track record of outperforming the basin, we are installing over 400 million cubic feet per day of compression in the first half of 2024, which will drive increasing volumes through our downstream assets. We currently estimate between $2.3 billion and $2.5 billion of growth capital spending in 2024 as we bring online two Permian plants, three fractionators in an NGL pipeline while also spending on projects that will come online beyond 2024, including additional Permian plants and fractionation trains. Beyond these projects already announced and under construction, we're also ordering long lead time items for our next Permian plants and frac Train 11 to ensure we keep pace with the significant activity we continue to see. Backed by the strength of our outlook and increasing stability of our cash flows we announced in November an expectation of a 50% year-over-year increase to our annualized 2024 common dividend per share. The increased dividend will be recommended to our board in April for the first quarter of 2024 with payment to shareholders in May. We also repurchased a record $374 million of common shares in 2023 and continue to be in position to execute on our opportunistic share repurchase program in 2024. Beyond 2024, we really like our positioning driven by a view of cost-advantaged basins like the Permian continuing to be a key supplier of hydrocarbons for decades to come. As we look to 2025, we estimate about $1.4 billion of growth capital spending burdened by the next major projects that are not currently board approved but would be necessary to support continued volume growth, including Train 11 and additional Permian G&P plants. With increasing EBITDA in 2025 relative 2024 and lower estimated growth capital spending, we expect to generate significant free cash flow in 2025. Also, we included in our presentation slides this morning an illustrative buildup of multiyear average spending that would approximate about $1.7 billion per year. This assumes high single digit gas volume growth in the Permian, requiring us to continue to add infrastructure across our value chain. $1.7 billion of capital spending at a 5.5 times multiple would drive over $300 million of EBITDA growth year-over-year and increasing free cash flow, supporting our ability to continue to return an increasing amount of capital to our shareholders. We also included our estimated spending to maintain volumes currently on our system, which we think is helpful in demonstrating the resiliency of our business. Growth capital spending to maintain existing volumes is estimated at around $300 million annually, which is informed by how quickly we're able to rationalize spending in 2020 and 2021, when we still had strong volume growth across our assets. In a scenario of $300 million of annual growth capital spend, we would be in a position to utilize significant free cash flow to continue to return capital to shareholders while maintaining a very strong balance sheet. As we look forward, our excitement is our -- our excitement and our outlook is driven by a few things. First, we have the largest Permian Gathering and Processing footprint in the industry with several million dedicated acres across Midland and Delaware Basins. That, coupled with an integrated NGL system, positions us nicely to generate high return organic opportunities to invest around $1.7 billion annually over a multiyear average, delivering over $300 million of annual EBITDA growth, driving significant free cash flow and positions Targa to continue to meaningfully increase the amount of capital returned to shareholders and deliver significant value to our shareholders over the long term. Let's now discuss our operations in more detail. Starting in the Permian, activity continues to remain strong across our dedicated acreage. Fourth quarter inlet volumes averaged a record 5.3 billion cubic feet per day, an 11% increase when compared to the fourth quarter of 2022. We brought online significant compression across our Midland and Delaware systems during the fourth quarter, driving a 5% sequential increase in volumes. In Permian Midland, our new 275 million a day Greenwood plant, which commenced operations during the fourth quarter, is already highly utilized. Our next Midland plant, Greenwood II, remains on track to begin operations in the fourth quarter of 2024 and is expected to be much needed when it comes online. In the Permian Delaware, activity in volumes across our footprint are also running strong. We brought online our new 275 million a day Wildcat II plant in late fourth quarter, and it's already highly utilized. Our Roadrunner II and Bull Moose plants remain on track to begin operations in the second quarters of 2024 and 2025, respectively. As mentioned earlier, we are ordering long lead time items for our next Permian plants to support continued production growth across our footprint. Shifting to our Logistics and Transportation segment. Targa's NGL pipeline transportation volumes were a record 722,000 barrels per day, and fractionation volumes were a record 845,000 barrels per day during the fourth quarter. Our Grand Prix NGL pipeline deliveries into Mont Belvieu increased 9% sequentially as we benefited from increased supply from our Permian G&P systems and higher third-party volumes. The outlook for NGL supply growth from our G&P footprint and third parties remains robust, and our Daytona NGL pipeline expansion will be much needed to handle growth from our system. We have obtained all required permits and have commenced construction on Daytona. We now expect the pipeline to begin operations ahead of schedule in early fourth quarter of this year, assuming favorable weather conditions. Our fractionation complex in Mont Belvieu continues to operate near capacity. And we expect our Train 9 fractionator to be highly utilized when it commences operations during the second quarter of 2024. The restart of GCF will also provide much-needed capacity when it is fully online during the second quarter of 2024. Our Train 10 fractionator is also expected to be much needed given the anticipated growth in our G&P business and corresponding plan additions and remains on track for the first quarter of 2025. As mentioned earlier, also ordering long lead items for Train 11 support continued production growth across our footprint. In our LPG export business at Galena Park, our loadings were a record 13.3 million barrels per month during the fourth quarter as we benefited from our recently completed expansion, strong market conditions and the Houston Ship Channel allowance of nighttime transits for larger vessels, providing strong momentum for 2024. Before I turn the call over to Jen to discuss fourth quarter results in more detail as well as our expectations for 2024, I would like to extend a second 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.

Thanks, Matt. Good morning, everyone. Targa's reported quarterly adjusted EBITDA for the fourth quarter was $960 million, a 14% increase over the third quarter. The sequential increase was attributable to higher Permian volumes, which resulted in higher system volumes across our integrated NGL business. Full year 2023 adjusted EBITDA was roughly $3.53 billion, supported by record financial and operational metrics across the company. We spent approximately $2.2 billion on growth capital projects and $223 million in net maintenance capital during 2023, largely in line with our previous estimates. In November, we successfully completed a $1 billion offering of 6.15% coupon senior notes due 2029 and a $1 billion offering of 6.5% coupon senior notes due 2034. This allowed us to reduce our term loan borrowings by $1 billion and enhance our liquidity position. At the end of the fourth quarter, we had $2.7 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 to 4 times. Also, this morning in an announcement that was made public while we were on this call, S&P has upgraded us to BBB, reflective of the progress we have made to date and our outlook for the future. Turning to our expectations for 2024. We are really excited about that short and longer term outlook. We estimate full year 2024 adjusted EBITDA to be between $3.7 billion and $3.9 billion, an 8% increase over 2023 based on the midpoint of our range, assuming commodity prices of $1.80 per MMBtu for Waha natural gas, $0.65 per gallon for our weighted average NGL barrel and $75 per WTI crude oil barrel. We expect first quarter 2024 adjusted EBITDA to be lower than fourth quarter 2023 as volumes across our systems were impacted by very cold winter weather, and operating expenses are increasing in anticipation of system expansions across both our segments. We expect quarterly adjusted EBITDA to increase sequentially as we move through the year and benefit from increasing volumes across our systems. We estimate $2.3 billion to $2.5 billion of growth capital spending for 2024, including the vast majority of spending on Greenwood II, Bull Moose, Daytona and Train 10. Our estimate for net maintenance capital spending is about $225 million reflective of our spending in 2023 and the increased assets that our operations teams are managing. We expect to end 2024 with our leverage ratio comfortably within our long-term leverage ratio target range of 3 to 4 times, providing continued flexibility going forward. We are well hedged across all commodities for the balance of 2024 and continue to add hedges for 2025 and beyond. The combination of hedges and fee-based margin across our businesses will continue to provide us with cash flow stability. Our fee floors in our G&P business support our ability to invest across lower commodity price environments while positioning us to benefit from higher commodity prices. Relative to our full year 2024 financial guidance, a 30% move higher in commodity prices would increase full year adjusted EBITDA by around $165 million, while a 30% decrease would reduce adjusted EBITDA by around $75 million. As Matt described earlier, we also provided you with our current view of 2025 growth capital spending and an illustrative multiyear buildup across a couple of scenarios. We hope these are helpful. Our goal in providing them was to highlight some key points. We believe that there will continue to be strong growth in Permian volumes on our system going forward, which is going to drive incremental volumes through our downstream assets, requiring continued investments, which will continue to be at attractive returns, particularly given our efforts around adding fees and fee floors. Downstream projects are larger and spending is lumpier. As those projects come online and we benefit from the operating leverage associated with increased available capacity, our growth capital spending moderates as evidenced by our current expectation of $1.4 billion of capital spend in 2025. Across multiple years, we would expect growth capital spend in an environment of continued volume growth to approximate around $1.7 billion. We are bullish Permian growth going forward but are often asked the question, how much capital would it take to maintain volumes? And our answer is approximately $300 million. This is not a scenario that we anticipate. It is merely intended to be instructive and hopefully helpful in demonstrating the strength of the Targa value proposition across the downside scenario, when the strength of our free cash flow generation and balance sheet would leave us very well positioned. Shifting 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. As Matt described, underpinned by the strength of our business outlook for 2024 and beyond, we plan to recommend to our board a 50% increase in the 2024 annual common dividend, $3 per share, and we expect to be able to grow our dividend meaningfully thereafter. We also expect to remain in a position to continue to execute opportunistically under our common share repurchase program. In 2023, we repurchased a Targa record $374 million of common shares at a weighted average price of $76.72 with $41 million repurchased during the fourth quarter. We had about $770 million remaining under our $1 billion share repurchase program at the end of the fourth quarter. Across our base scenarios, we are continuing to model the ability over time to return 40% to 50% of cash flow from operations to equity holders, providing a framework for thinking through our return of capital proposition looking forward. As it relates to taxes, based on our estimate for earnings and spending and current tax policy, there's no change to our assumptions that we may be subject to the federal minimum tax in 2026 and a full cash taxpayer in 2027. We believe that we continue to offer a unique 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 assets -- outlook, excuse me. Our talented team continues to execute on our strategic priorities and safely operate our assets to deliver the energy that enhances our everyday life. And we are very thankful for the efforts of all of our employees. And with that, I will turn the call back over to Sanjay.

Thanks, Jen. For the Q&A session, we kindly ask that you limit to one question and one follow up and enter the Q&A line up if you have additional question. Shannon, would you please open the line for Q&A?

Thank you. [Operator Instructions] Our first question comes from the line of Jeremy Tonet with JP Morgan Securities, LLC. Your line is now open

Hi, good morning.

Hey, good morning, Jeremy.

Just wanted to start off, I guess, with the news about 2025 CapEx stepping down so significantly versus 2024, creating a lot of flexibility there as it relates to return on capital. Just wondering if you might be able to provide a little bit more detail as far as thoughts on capital allocation at that point in weighting dividend growth relative to buybacks. Just kind of any other -- any incremental color would be helpful there with that extra -- with that $1 billion step-down in CapEx.

Good morning, Jeremy. This is Jen. I think that we're really excited about 2025 and the possibilities for Targa and our shareholders. There's really no change to how we are thinking about return of capital. I think part of the excitement that we have around this year, next year and really many years to come is that we believe we offer a really unique value proposition, where we will be in position from a significantly increasing amount of free cash flow to meaningfully increase our common dividends per share and continue to execute under our opportunistic share repurchase program. We published the framework in November that said that we would expect to be in a position to return 40% to 50% of cash flow from operations to our shareholders. And that's what we're modeling. And as we get into 2025 and beyond, that means that there's a lot of incremental capital that can flow to our shareholders. And again, that's really what is underpinning what we think should be a very exciting Targa story for both our company and our shareholders.

Got it. Thank you for that. And maybe just pivoting towards LPG exports, a good step-up there. Just wondering if you could comment a bit more if the lifting of daylight hour restriction, I think, it is planned and we expect the Port Authority to drop the trial moniker not too far down the road here. I'm just wondering how you think that impacts Targa capacity when the daylight hour restriction is fully removed then?

Hey, Jeremy, this is Scott. First off, you're right, fourth quarter was a really nice quarter for us with over 13 million barrels per month, which was a combination of both propanes and butanes across the dock. Certainly, a couple of benefits there that we took in -- to our advantage. One was obviously the export expansion project that we had that increased our refrigeration capacity, increased our ability to load vessels faster. And we were able to operate through the -- really the entire fourth quarter, so we got the step up with that. The nighttime transits that were lifted or provided another benefit. So the Houston Ship Channel, along with the Houston pilots, collaborated together to provide that to the industry as a whole. Targa benefited from that as a result of that. I would say that nominally speaking, we think that, that probably provided us about a 5% to 10% benefit. It's difficult to really pin that down because there's a variety of factors that play into that. And on top of that, we were able to benefit from spot activity as a result of those increased liftings. I would like to add that I give a huge thank you to the Houston pilots and the Houston Ship Channel. That provides that change in nighttime transit that they have done very safely, effectively and efficiently, not only benefits Targa, but it really benefits a wide variety of industries along the Houston Ship Channel that help drive Texas economy as well as the U.S. economy. So going forward into 2024, you're right, currently today it is kind of labeled as a trial period. But I think based upon the success that they've had, the safe operating environment that they've been able to conduct themselves under, we view this really as a long-term change. And we will continue to benefit from it. We hope to find other ways to optimize around that as we learn more about the nighttime transits and the vessels that are available to move through that process.

Got it. Okay. So it sounds like there could be upside down the road versus the 5 to 10?

Well, what I would say is, I think that in the fourth quarter, it was not -- the nighttime transits were not a part of the entire fourth quarter. It really got instituted in November. And I think that we will hopefully find some better ways to optimize around it, again, as we learn more about the program. So it benefited us now, and we'll continue to see how that fares for us going forward.

Yeah. It's still early, Jeremy. So I think we're thinking 5% to 10% is a good -- kind of a good range of upside right now, but it's still pretty early.

Got it. That’s helpful. Thank you.

Okay, thank you.

Thank you. Our next question comes from the line of Spiro Dounis with Citi. Your line is now open.

Thanks, operator. Good morning, team. Wanted to go back to Permian production quickly. Jen, you had mentioned maybe a slower start to the year, and I think that's pretty consistent with what producers are saying. Just curious, though, as we think about the year as a whole, can you give us a sense of what Permian production growth is underwriting the guidance? And to the extent that it's back half loaded, what that implies about 2025?

I think that we're continuing to see a lot of very robust growth on our Permian assets. A couple of important points that I think were mentioned in scripted comments were, one, that by the time that we got to the end of 2023, we actually outpaced our initial expectations for the year. While that growth materialized a little bit more slowly than we expected, it did materialize and ended up exceeding expectations at year-end. What I was trying to highlight was we did experience some extreme winter weather here thus far to start the year, and that will impact our Q1 results. But our operations teams are doing an excellent job of getting our assets back up and running. So as we think about the balance of this year and beyond, I think you've seen our track record that we outperform the expectations for growth out of the Permian Basin on the gas side. And there's nothing that we're seeing that would change that trend in any meaningful way. We didn't give a statistic this year for Permian growth relative to what we've provided previously in the past. One, just because we think that individual operational statistics are less meaningful than some of the high-level corporate information that we give. And I think that our performance in 2023 highlighted that a little bit, right? Our volumes ended up coming in a little bit lower than our initial guidance for the full year average. But again, we exited higher than we initially anticipated. So everything is just really setting up well for our continued execution across both the Midland and the Delaware Basin. And we have a very strong outlook for robust continued growth for as long as we can see.

Got it. Thanks a lot, Jen. Second question, maybe going to 2025. I know you're not providing '25 EBITDA today, but some of the materials did maybe give us some tools on how to help think about that. You guys are pointing to significant growth. You've also talked about in the slides $300 million of annual EBITDA growth with $1.7 billion of spending. So I guess, if I look back at '23-'24, spending over $2 billion in each of these years, it would seem like as we think about the lease of '25, over $300 million of EBITDA growth would seem like an easy hurdle. But I don't want to get too ahead of myself.

Yeah, yeah. I think what I'd say is we feel really good about our position coming out of '24 going into '25. I think '25 is going to set up very well. I think we see significant EBITDA growth in '25, and frankly, beyond '25. We guided 2.3 to 2.5 of CapEx this year. We were about 2.2 last year. So the kind of 5.5 times investment multiple is a multiyear average. It's not -- you spend a set amount in one year so it results in EBITDA in that year. It's a multiyear average that we think we can do, call it, 5 to 6 times EBITDA on our CapEx. So when you kind of look at what we spent the last couple of years, I think it just sets up for a very strong 2025. We decided not to give EBITDA guidance for '25, but just kind of point you to our historical spending and just the overall volume trajectory that we're seeing across our footprint is just going to set up very nice for us in '25.

Fair enough. Thanks for that, Matt. Appreciate the time today.

Okay. Thank you.

Thank you. Our next question comes from the line of Brian Reynolds with UBS. Your line is now open.

Hi, good morning everyone. Maybe to follow up on some of the kind of long-term EBITDA growth outlook, I think you outlined kind of a build multiple around 5.5 times. I think a quarter or two ago, you kind of outlined in the past three years that some of these projects came in at much lower multiples. So kind of just trying to understand maybe the difference there if you can -- maybe there's some doses of conservatism in the build or whether the commodity has anything to play with that and whether we could maybe see some upside to the EBITDA build multiple. Thanks.

Sure. No, good question. I mean, really, historically, you go back years, we kind of said 5 to 7 times build multiple is kind of what we targeted. We've been able to do better than that. I think that was just kind of some cushion in that 5 to 7. If you look back at the last five years, we've really been kind of closer to a 4 times build multiple. We've had really good volume growth across our system. And the Permian, Grand Prix filled up much quicker even than our expectations, which just drove the returns even higher. So I think we've really had some strong performance. But I'd say there's really nothing fundamentally different in what we're investing in this year and next year, go forward than what we invested in, in the past where we did have a lower investment multiple. I'd say perhaps there's a little bit of conservatism put into that number. But it's not -- there's not a large delta from commodity prices one way or the other. I'd say we have more commodity price upside given the fee floors that Jen and we've talked about, which could drive that lower if we get some commodity price tailwinds.

I would just add that, I think, Brian, the conservatism is further highlighted by how highly utilized we think our projects will be that are in progress right now when they come online, which has been really the same playbook that we benefited from over the last many years. It feels like we're just in time on a number of our assets, which is great for the finance person in the room because it means that they're very highly utilized at start-up and provide significant incremental cash flow very quickly. It makes it a little bit tougher for our operations and engineering teams, of course, as they try to plan. But I think that that's part of the conservatism as well that really is reflective in the 5.5 times versus the realized multiples that you've seen across our footprint.

Great. Thanks. And maybe as a follow-up to Spiro's question on just Permian and the growth. Previously, you kind of gave more of a firm number around 10%. And then the illustrative guide, you kind of talk high single digits. Maybe just talk about that's kind of your base expectation at this point. And then kind of as a follow-up, has any of the M&A -- any updated view on some acquisitions in the Midland impacting your thought process there? And then just on the operational hiccups, are we past that? And as it relates to H2S gas quality issues, how does your system able to manage that sour gas and potentially grow at a higher clip than the rest of the basin? Thanks.

Okay. I'll start and then Pat can probably touch on a little bit of this, too. I think when you look at our Permian growth for the year, we really feel good about where we're starting the year. December was our highest month, and it really just sets us up for really good production growth just where we exited 2023 going into '24. So even with relatively modest growth from here, we're going to see a really strong year-over-year. And that's why we've said consensus is about 9%. We've typically beat that. But even if we get anywhere around high single digits or a little bit better, I think it sets us up very well, not only for '24 'but 25. And then I'll let Pat speak a little bit to kind of the M&A landscape from our E&P customers.

Yeah. There's been a lot of M&A activity over the last three to four years. So it's not something we're unfamiliar with. And frankly, we don't see a material difference with these new announcements as we've seen in the past. Frankly, we've seen pretty consistent growth across the combined companies relative to our position with the individual companies. The new ones that are coming out, we have meaningful positions with all the parties. We have long-term contracts with all the parties. We have great relationships with all those producers. If you look at what's been publicly announced by those parties, you wouldn't expect a significant impact to what their expected growth levels are going to be. Frankly, at least on one of the major -- the bigger mergers, there's -- you could allow that there's going to be an expectation of incremental growth on our assets on the Midland side of the basin. So there is a lot of activity, a lot going on, but we've benefited from it because we've got great assets, we're reliable. We've got good contracts, and we've got good relationships.

Yeah. And just to add to that, too, the other part of your question was around gas quality and trading. A lot of the -- we are spending a lot of capital, and we spent last year and this year 4 additional treating facilities primarily in the Delaware Basin. We're putting in some additional treaters to handle both CO2 and H2S, and we're drilling multiple wells to handle that as gas injection wells and pipelines and connectivity to handle that. So I think that really positions us nicely as the Delaware continues to grow and gas quality becomes another issue that the producer are going to have to deal with, we'll be in a really good position to handle that. And most of that capital will be in or the large -- the lion's share of it will be in kind of by the end of this year.

And then I think the very last question in your question was around whether volumes had rebounded as a result of the impact of winter storm. And I'm really proud -- I think we're all really proud of the efforts of our operations teams to get volumes back online. So we're close to back to levels that we were seeing before we experienced the extreme weather.

Great. Thanks. Appreciate all the color this morning. Thanks.

Okay, thank you.

Thank you. Our next question comes from the line of Tristan Richardson with Scotiabank. Your line is now open.

Hi, good morning. Jen, pardon, my voice this morning, but really appreciate the CapEx sensitivity you guys laid out and really curious about the flexibility you have in that '25 outlook. Certainly, you talked about that high single digit embedded in that assumption. But can you talk about timing that spend in the event producers deviate from that assumption, whether that is deferring Train 11 timing your plan towards the end of '25? And then also maybe just about does Greenwood II and Bull Moose coming on towards the second half of '24? Is that adequate capacity to support that sort of high single-digit inlet for '25 in the illustrative?

Yeah. So as we think about '24 and then going into '25, we're ordering some long lead time, have some spending for Train 11, which will both be in '24 and '25. And then we also mentioned there's additional plants, call it, two plants, maybe one in the Delaware, one in the Midland, of additional ordering long lead time and in kind of our base assumption that we're going to need to start spending capital on this going to have '24 and '25 budget. So that's kind of what we have in our budget right now. Sure, if there's even more production growth in the Permian, could that move that plant timing up a little bit? It could move it up a little bit. If it's perhaps on the lower end of the growth ranges, could we push those out? Yeah, we could push that out a little bit. Really, the big sensitivities to our CapEx does -- it really tends to be more on the downstream side. Are we going to need -- when is the next fractionator? What about -- Daytona's coming on, should give us some good runway from an NGL perspective. But when will you need more transportation and then export? Those are the larger projects that can be a bit lumpier. So I think '25, a lot of that up and down really could just be around our G&P business and some of the plant timing and related field capital.

Super helpful. Appreciate it, Matt. And then just a quick follow-up. Talking about the 90% fee-based now. I mean, I think a substantial move from '23. Clearly, this is a multiyear priority for you guys and has been a game of inches. Are you seeing a big change in '24 really a function of mix? And where -- which of your producers are growing? Or did you see some substantial kind of recuts or recontracting occur throughout '23?

Yeah. We've been making steady progress on getting more fee-based components, primarily fee floors but also just fee-based G&P business, over the last several years. Our commercial team really did a fantastic job in 2023. And I would say there was a step-change in just the number of contracts that we were able to get redone. So no, it was a step-change late in '23, which significantly changed our overall downside risk profile and is done. So now we're estimating 90%. You see that on our commodity price sensitivity. We still have some length. So there is some downside if prices moved down. But relative to our overall size of 30% downside, $60 million, $70 million, that's not much sensitivity. That is fundamentally different than where we were really 12-24 and certainly 36 months ago.

Yeah, appreciate. Thanks very much, Matt.

Okay, thank you.

Our next question comes from the line of Theresa Chen with Barclays. Your line is now open.

Good morning. I have a question following up on Tristan's question related to the fee floors within your G&P segment. Just thinking about the 90% at this point, as you have put in additional fee floors within your POP contracts overtime, is the mix of fee-based versus POP with the floor within that 90% changing, i.e. is the incremental fee-based contract really putting in fee floors for POP? Or have you exchanged some previous legacy fee-based contracts for POP with the floors as you renegotiate? And just really trying to understand the rationale behind why your customers would allow you to put in fee floors overtime.

This is Jen. It's actually a mixture of what you talked about but for different reasons. You've seen the percent of our G&P business that is fee-based increase largely as a result of acquisition. When we bought Lucid, primarily underpinning the Lucid contracts that we acquired were largely fee-based contracts. And so we saw a big step change in the increase of fees generated from our G&P business associated with that acquisition. But what our commercial team has been really successful at doing, and I would also like to take my hats off to all of them because it's been just a huge effort that I think has very meaningful implications for our company, is they have gone in and worked with producers to really demonstrate that in order to incentivize Targa to be willing to spend capital. And this goes back to 2020. This is an effort that we have been building on -- building momentum on over the last many, many years. But going back to those conversations, in order for Targa to be willing to continue to invest capital, what you've seen us consistently do over the last many years. We need to make sure that we will get an adequate rate of return in a downside commodity price environment. It's simply just the math. And our producers have been very supportive of that construct. So we've gone into existing POP contracts, and we've been able to restructure those to put the fee floors in place that, again, have incentivized us to continue to spend capital even as commodity prices are lower while not giving up the upside to the extent commodity prices rise. And so it's really been a mix of we've acquired a lot of fee-based assets on the G&P side, and then we've gone in and we've either restructured existing contracts or as new contracts have been put in place by our commercial team, they've been put in place with that fee floor structure while also generating returns across our integrated system. And the commercial teams have really just done a very good job supporting our producers with what our producers need but under a construct that also works for us to continue to capital.

That's helpful. Thank you. And then when we think about the long-term illustrative CapEx, so going from 1.4 back to the 1.7 on a multiyear basis and thinking through the next lumpy projects in the downstream segment. In addition to additional fractionation and export capacity, the eventual looping of the 30-inch segment of Grand Prix, can you talk about at this juncture with the growth that you have had you and Daytona coming online by year-end and filling up thereafter, what the cadence of build and spend would be for that 30-inch loop? And how do we get from 1.4 to 1.7 or beyond in the years to come?

Yeah. Sure. Good question. So I would say the primary delta from the 1.4 to 1.7 is downstream spending, having multiple fractionation facilities and that's really more this year. But really the delta between 1.4 and 1.7 is primarily downstream. One of the larger projects that we don't have any meaningful spending on next year is transportation, another NGL pipe. We have Daytona coming on this year. That's going to provide us some good runway. So then how much runway that provides really depends on what the overall growth rate in the Permian and our capture of those NGL barrels to move on to Daytona. So that is something we're thinking about. These pipes take a couple of years to get billed, probably even a little bit longer than that. So we had to look out two-three years and say, when do we need to think about looping that 30-inch segment. There's also available transport out there from some of our competitors. So we can move -- I think we'll move the lion's share of our volumes on our own pipe. There can be transportation agreements that can be had with some of our competitors as well. So really, for us, all options are on the table, whether it's us building a 30-inch down the road or utilizing some excess capacity from some other NGL pipes.

Yeah. And Matt, I would just add the fact that our West leg, we've shown that we can actually operate that above the 600,000 barrel a day nameplate that we have kind of put out there. So that volume along the West leg, along with volumes that are coming in from the north are all feeding through the 30-inch pipeline. We've got still a lot of operating leverage with the 30-inch pipeline. And certainly, Daytona provides us a lot of operating leverage going forward for periods of time.

Thank you.

Okay, thank you.

Our next question comes from the line of Neel Mitra with Bank of America. Your line is now open.

Hi, good morning. Thanks for all the detail on the CapEx spend. I wanted to follow up on the last question and the $550 million related mostly to downstream. Assuming you're spending about half of a frac each year, that leaves about $300 million each year for, on average, transportation and exports. So first of all, is there any ability to meaningfully expand Galena Park at this time? Are there land constraints? And then second, with the NGL pipe build oversupply, do you see your need for expanding pipe elongated just because you're able to hold your pricing power when others are competing for barrels?

Neel, this is Scott. I'll start it off and just say that let's -- when we first think about the pipe, recognize that today, we utilize third-party pipes for volumes that are coming into our Belvieu facility today. And when we think about the growth that we have on the G&P side and the Daytona pipeline, we are not out there fighting for fees relative to fill up our existing capacity and our expected capacity that we would have on Daytona. So all of that kind of folds hand-in-hand with the growth that Pat and his team on the G&P side have relative to transportation. Matt alluded to the fact that if there is capacity on industry pipes, we -- again, because we utilize that today, we can always look for opportunities to utilize that to bridge us to whenever we might need to do a loop around our existing system. As it relates to Galena Park, we have a really good idea of what the next expansion project looks like. And it's a variety of factors from adding refrigeration to adding pipe, to adding potential docks and things of that nature. So we're keeping, obviously, a close eye on what that timing needs to be relative to our growth, again, driven by our G&P business. And we'll continue to evaluate that. So I will say, again, the expansion that we had in the fourth quarter that we're benefiting from today, the nighttime transits, both of those really are hand-in-hand expansion projects on their own without having to spend a lot of capital. So we'll continue to look for ways to debottleneck if possible to get incremental capacity as well. So I think we've got a lot of opportunity and some runway with the existing assets that we have. But we do have space available to expand at Galena Park.

Perfect. And if I could just follow up quickly. One of your peers mentioned for their oil outlook in the Permian that almost all of the growth would come out of the Delaware versus the Midland. I know that you aren't necessarily representative of the overall basin. But could you just perhaps break out what you're seeing with producer activity between the two basins in the Permian?

Yeah. I mean we see growth in the Delaware, but we see significant growth in the Midland as well. So we see growth across both of our footprints, really active producers in both. So on our footprint, we see growth in the Midland and we see growth in the Delaware.

Okay, thank you.

Thank you.

Our next question comes from the line of Keith Stanley with Wolfe Research. Your line is now open.

Hi, good morning. One follow-up on Daytona just thinking to next year, 2025. Do you expect volumes on Daytona to simply tie to Targa G&P volumes? Or are there material third-party volumes that you're expecting to pick up when the pipeline comes into service?

Hi, Keith, this is Scott. I would say it's predominantly driven by our G&P footprint as to what we'll be feeding into Daytona. So it is a combination, but I would say the largest proportionate share of that is going to be related to our G&P and the additive of the plants that we've already announced and any potential plants going forward.

Got it. Thanks. And then, Jen, wanted to clarify on the cash taxes. So expectation, I think you said full 15% AMT cash tax rate in '26 and then statutory 21% tax rate in 2027. And then relatedly, how would that house pass legislation, which brings back bonus depreciation potentially impact that outlook?

We are pretty borderline right now, whether we would be subject to the AMT in 2026 or 2027. It's actually pretty close. So that -- we're trying to give you a conservative look right now that -- based on our latest forecast we may be subject to the AMT. And then in that scenario, in 2027, we'll have worked our way through our net operating losses and would be fully subject to the statutory tax rate. To the extent the existing bill that -- moving its way through gets passed, and we do see a return of accelerated bonus depreciation, that would be a big help to us. And that may delay things, call it, a year or so based on current forecast. Ultimately, we'd have to see what the final policy is that gets passed, but that would be our early read right now.

Thank you.

Thank you.

Our next question comes from the line of John Mackay with Goldman Sachs. Your line is now open.

Hey, thanks for the time. I wanted to go back to the potential export expansions. Maybe this is one for Scott. I appreciate the color. But I guess when you guys are looking high-level, top-down from a strategy standpoint, if we think about the quantity of NGLs coming off your Permian processing footprint and how much of that on a percentage basis moves its way on to the export side, do you want to be able to hold that percentage going forward? Are you comfortable with that percentage dropping? Do you want to increase it? Just any kind of directional strategy thought would be interesting.

Yeah. Sure. Yeah. As we think about really from G&P all the way through our dock, we want to make sure we have the capacity to handle the volumes coming from our G&P footprint. And so that's kind of how we think about staging transportation, fractionation. And that goes for export as well. We want to make sure we have a good market for propane and butanes. As Scott mentioned, that's really what we export. So with the expansion that just came on and the nighttime allowance of kind of, call it, 5% to 10%, I think that gives us some cushion as we go forward. And as we see really how much capacity that nighttime opens up for us, that gives us some good cushion before we're going to need another export project. But we are already looking at scoping. And so the timing is kind of to be determined, but do we need refrigeration, do we need a pipeline, are we looking at dock. But those projects are not the really large-scale, I'd say, greenfields or brownfield. I kind of view those as more debottlenecking. You have one pinch point, you spend a couple of hundred million dollars and you get some excess capacity, then you do the next and then you do the next. So those are the things we're kind of looking at over the longer term. But yeah, we want to make sure we can handle the volumes coming across our system.

That's clear. Thank you. Maybe just one last quick one. You mentioned you'd caught up on the compression side. Obviously, we've been hearing about tightness in the compression market across the board. One of your peers talked about this as being a potential relative guardian on growth even going forward from here in the Permian. Maybe just your high level thoughts and whether that actually is a bit of a constraint at this point or it's gotten better versus third quarter.

Yeah. I mean we have the issues we talked about last year was really just kind of being behind on our -- getting the compression all said and getting that done last year. We had a lot of compression come on late last year, and then you saw our volumes in Q4 really move up. We have another talked about $400 million of compression. So we ordered that out about a year right now for compressors. So we tried to get ahead of it as we saw we were getting behind last year. We just approved another AFE the other day to order some more inventory to try and get ahead of it and stay for 2025. So part of that does depend on volume growth. When you see a lot of volumes, if it exceeds our forecast, you can end up having some pinch points. But we're trying to be smart, look at the forecast and stay ahead of it.

Yeah. And I think the only thing I'd add, Matt, is lead times have not come down. The lead times are still long. So that problem still exists. We've just gotten out in front of it.

If I could just ask one follow-up on that. Caterpillar announced a capacity expansion on their large engine line, I guess, a week or two ago. Any initial read on whether that should bring that down from a year to something a little better?

I have not heard any change in lead times.

Fair enough, thank you. Appreciate the time.

Okay, thank you.

Our next question comes from the line of Michael Blum with Wells Fargo. Your line is now open.

Thanks for squeezing me in. Just wanted to ask if any update on the Apex Permian gas pipeline? And I'm assuming the $1.7 billion run-rate does not contemplate that project.

This is Bobby. We continue to work on all the options to get gas out of the basin, which includes Apex. We've said it before and we'll say it again, our number one priority is that gas continues to flow out of the basin so that NGLs can come out of our plants and go down Grand Prix and go across our docks. Last call, I think I talked about the fact that several other projects that fit the parameters that we would want to -- back have raised their heads. And we're working hard on those along with Apex and everything else. So I am -- every month that passes, I get more encouraged by the work we're doing to make sure that a pipe gets built and comes online '26-ish. And I'm confident that something will get done this year, whether that's an Apex or one of the multiple options that we're looking at to increase egress out of the basin.

Yeah. No. And then, Michael, on the CapEx part, that is not included in the 1.4. In any project that goes, we'll evaluate does it make sense for us to be a partner. So for a partner in it that would increase that CapEx. There's also some of these pipes that will be project financed for the majority of the capital. So any amount of equity we were to put into it would be relatively small, so it may or may not be project financed. But that is not included in the -- in our outlook.

And I'd just add one last point that in the $1.7 billion, we have been spending some capital in the last couple of years on what I call intra-basin Permian residue just to ensure we've got really good redundancy on the residue side between our plants. So to the extent that we're contemplating any of that in the future, that will be included in that $1.7 billion multiyear outlook, but no major projects.

Okay. Got it. No, that helps. And then just on Frac 11 that I guess you're starting to spend a little bit on this year, what's the timing of when that would be in service? Thanks.

Yeah. Hey, Michael, this is Scott. We've not defined what the timing would be for that in-service date. Ordering long lead items gives us some flexibility on what that needs to be out into the future. We're just finding that supply chain planning -- or supply chain issues are creating some issues with certain equipment. And so as a result of that, we can take some small capital dollars to ensure that we can hold whatever date we put out there in the future. So we don't have a defined date at this point, but it's certainly something that we want to keep on our radar and keep ahead of.

Thank you.

Yeah, thanks, Michael.

Thank you. This concludes the question-and-answer session. I'd now like to hand the call back over to Sanjay Lad for closing remarks.

Thanks to everyone that was on the call this morning, and we appreciate your interest in Targa Resources. The Investor Relations team will be available for any follow-up questions you may have. Thanks and have a great day.