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. 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. I would like to recognize and thank our employees for their focus, dedication, and execution throughout the year. Some 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 and on budget, and have been highly utilized since start-up; we ended the year with 90% of our G&P volumes fee-based or with a fee floor; a positive outlook for our current investment-grade ratings with each of the three agencies, and the successful completion of two notes offerings; and a higher year-over-year return of capital to our shareholders through an increased common dividend and record common share repurchases. Our performance was particularly strong considering that Waha natural gas and NGL prices were about 64% and 34% lower year-over-year. We benefited from margin from fee floors in our Gathering and Processing business across 10 of 12 months, showing our business is more resilient to falling commodity prices than ever. We ended 2023 with considerable 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 came later than expected in 2023, we are pleased to have ended the year with December actuals aligning with our original guidance expectations for the Permian, providing us with strong momentum into 2024. We expect another year of record financial and operational metrics, with full-year adjusted EBITDA projected to be between $3.7 billion and $3.9 billion for 2024. This significant year-over-year increase in adjusted EBITDA is primarily driven by anticipated higher Permian Gathering and Processing volumes and increased NGL transport, fractionation, and export volumes. Consensus growth expectations for Permian-associated gas in 2024 are about 9%. Given our track record of outperforming the basin, we are adding over 400 million cubic feet per day of compression in the first half of 2024, which will boost volumes through our downstream assets. We currently estimate growth capital spending for 2024 to be between $2.3 billion and $2.5 billion as we bring online two Permian plants, three fractionators, and an NGL pipeline, while also investing in projects that will come online beyond 2024, including additional Permian plants and fractionation trains. In addition to these announced projects under construction, we are ordering long lead time items for our next Permian plants and frac Train 11 to ensure we stay aligned with the significant activity we continue to experience. Supported by our strong outlook and increasing stability of cash flows, we announced in November an expected 50% year-over-year increase in our annualized common dividend per share for 2024. 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 are well-positioned to continue our opportunistic share repurchase program in 2024. Beyond 2024, we are optimistic about our positioning, driven by our belief that cost-advantaged basins like the Permian will continue to be key suppliers of hydrocarbons for decades. As we look to 2025, we estimate about $1.4 billion of growth capital spending, influenced by the next major projects that are not currently board-approved but are necessary for continued volume growth, including Train 11 and additional Permian G&P plants. With increasing EBITDA in 2025 relative to 2024 and lower estimated growth capital spending, we anticipate generating significant free cash flow in 2025. Additionally, we included in our presentation slides an illustrative multiyear average spending buildup that would be approximately $1.7 billion per year. This assumes high single-digit gas volume growth in the Permian, necessitating continuous investment in infrastructure across our value chain. At $1.7 billion of capital spending at a 5.5 times multiple, we would expect over $300 million of EBITDA growth year-over-year and increasing free cash flow, which would enable us to continue returning capital to shareholders. We also estimated our spending to maintain volumes currently on our system, which we believe illustrates the resiliency of our business. Growth capital spending to maintain existing volumes is estimated at around $300 million annually, informed by how quickly we rationalized spending in 2020 and 2021, despite strong volume growth across our assets. In a scenario with $300 million of annual growth capital spending, we would be in a position to utilize substantial free cash flow to continue returning capital to shareholders while maintaining a very strong balance sheet. Looking ahead, our excitement and outlook are driven by several factors. First, we have the largest Permian Gathering and Processing footprint in the industry with millions of dedicated acres across Midland and Delaware Basins. Combined with an integrated NGL system, this positions us well to create high-return organic investment opportunities of around $1.7 billion annually over multiple years, resulting in over $300 million of annual EBITDA growth, driving significant free cash flow and allowing Targa to continue to significantly return capital to shareholders and provide substantial long-term value. Now, let's discuss our operations in greater detail. In the Permian, activity remains strong across our dedicated acreage. Fourth quarter inlet volumes averaged a record 5.3 billion cubic feet per day, an 11% increase compared to the fourth quarter of 2022. We effectively brought online significant compression across our Midland and Delaware systems during this quarter, resulting in a 5% sequential volume increase. In Permian Midland, our new 275 million day Greenwood plant commenced operations in the fourth quarter and is already highly utilized. Our next Midland plant, Greenwood II, is on track to begin operations in the fourth quarter of 2024 and is expected to be necessary when it comes online. In the Permian Delaware, we are also seeing strong activity and volume across our footprint. Our new 275 million day Wildcat II plant began operations in late fourth quarter and is already highly utilized. Our Roadrunner II and Bull Moose plants are on track to begin operations in the second quarters of 2024 and 2025, respectively. As mentioned, we are also ordering long lead time items for our next Permian plants to support continued production growth in our footprint. In our Logistics and Transportation segment, Targa's NGL pipeline transportation volumes reached a record 722,000 barrels per day, and our fractionation volumes were also a record 845,000 barrels per day in the fourth quarter. Our Grand Prix NGL pipeline deliveries into Mont Belvieu increased by 9% sequentially as we benefit 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 strong, and our Daytona NGL pipeline expansion is necessary to accommodate growth from our system. We have secured all necessary permits and have begun construction on Daytona, now expecting 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 anticipate our Train 9 fractionator to be highly utilized when it starts operations in the second quarter of 2024. The restart of GCF will also be crucial for capacity when it is fully online during the second quarter of 2024. Our Train 10 fractionator is expected to be essential given the anticipated growth in our G&P business and corresponding planned additions and is on track for the first quarter of 2025. As noted, we are also ordering long lead time items for Train 11 to assist in continued production growth across our footprint. In our LPG export business at Galena Park, we achieved record loadings of 13.3 million barrels per month during the fourth quarter, benefiting from our recent expansion, strong market conditions, and the Houston Ship Channel’s allowance for nighttime transits of larger vessels, providing strong momentum for 2024. Before I hand the call over to Jen to discuss fourth quarter results in more detail as well as our expectations for 2024, I want to extend my thanks once again to the Targa team for their unwavering attention to safety and execution while consistently delivering 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. This increase was due to higher Permian volumes, which led to greater system volumes in our integrated NGL business. For the full year 2023, adjusted EBITDA was approximately $3.53 billion, benefiting from record financial and operational metrics across the company. We invested around $2.2 billion in growth capital projects and $223 million in net maintenance capital during 2023, consistent with our previous estimates. In November, we accomplished a $1 billion offering of senior notes with a 6.15% coupon due 2029 and another $1 billion offering with a 6.5% coupon due 2034. This allowed us to cut our term loan borrowings by $1 billion and improve our liquidity. At the end of the fourth quarter, we had $2.7 billion in available liquidity, and our net consolidated leverage ratio was about 3.6 times, comfortably within our long-term target range of 3 to 4 times. Additionally, S&P upgraded us to BBB this morning, reflecting the progress we've made and our outlook for the future. Looking ahead to 2024, we are excited about both our short- and long-term outlook. We anticipate full year 2024 adjusted EBITDA to be between $3.7 billion and $3.9 billion, reflecting an 8% increase over 2023, 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 that of the fourth quarter 2023 due to the impact of extremely cold winter weather on volumes across our systems and increasing operating expenses in preparation for system expansions. We project quarterly adjusted EBITDA to rise as the year progresses due to increasing volumes. We estimate growth capital expenditures for 2024 to be around $2.3 billion to $2.5 billion, primarily directed toward Greenwood II, Bull Moose, Daytona, and Train 10. We expect net maintenance capital expenditure to be about $225 million, consistent with our 2023 spending patterns and increased assets managed by our operations teams. We aim to end 2024 with our leverage ratio well within our long-term target range of 3 to 4 times, ensuring continued flexibility moving forward. We are also well hedged across all commodities for the remainder of 2024 and continue to add hedges for 2025 and beyond. The combination of hedges and fee-based margin in our businesses will provide us with cash flow stability. Our fee floors in the G&P business support our investment strategy in lower commodity price environments while allowing us to benefit from higher commodity prices. Regarding our 2024 financial guidance, a 30% increase in commodity prices would raise full year adjusted EBITDA by about $165 million, while a 30% drop would reduce adjusted EBITDA by roughly $75 million. As mentioned earlier, we've shared our current projections for 2025 growth capital spending and illustrative multi-year scenarios, which we hope you find useful. We believe there will continue to be strong growth in Permian volumes on our system, ultimately enhancing volumes through our downstream assets and necessitating further investments with attractive returns, particularly due to our efforts to implement fees and fee floors. Downstream projects are larger and have uneven spending patterns. As these projects become operational and we take advantage of the increased capacity, our growth capital spending will normalize, as indicated by our current expectation of $1.4 billion in capital expenditures for 2025. Over the long term, we expect growth capital spending to be about $1.7 billion in a scenario of continued volume growth. We are optimistic about Permian growth but often receive inquiries regarding the capital needed to maintain volumes, which we estimate at about $300 million. This is not a scenario we predict, but is intended to illustrate the strength of Targa’s value proposition during downturns, showcasing our robust cash flow generation and solid balance sheet. Regarding capital allocation, our priorities remain unchanged: maintaining a strong investment-grade balance sheet, investing in high-return integrated projects, and increasing capital returns to our shareholders. As previously mentioned, based on our positive business outlook for 2024 and beyond, we plan to recommend to our board a 50% increase in the 2024 annual common dividend to $3 per share, with expectations for meaningful growth thereafter. We also anticipate continued opportunities to execute under our common share repurchase program. In 2023, we acquired a record $374 million of common shares at a weighted average price of $76.72, with $41 million repurchased in the fourth quarter. We had about $770 million remaining under our $1 billion repurchase program by the end of the fourth quarter. Across our projected scenarios, we continue to model the potential to return 40% to 50% of cash flow from operations to shareholders, guiding our return of capital strategy moving forward. Regarding taxes, based on our earnings and spending estimates along with current tax regulations, we have no changes to our outlook for being subject to the federal minimum tax in 2026 and becoming a full cash taxpayer in 2027. We continue to present a unique value proposition for our shareholders, marked by growing EBITDA, increasing common dividends per share, reduced share count, and strong asset outlooks. Our dedicated team is committed to executing our strategic goals and safely managing our assets to provide essential energy. We appreciate all our employees' hard work. I’ll now turn the call back 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 lineup if you have an additional question. Shannon, would you please open the line for Q&A?

Thank you. 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.

I wanted to start by discussing the significant reduction in 2025 capital expenditures compared to 2024, which provides us with increased flexibility regarding our return on capital. Could you share more details about your thoughts on capital allocation, particularly in balancing dividend growth with share buybacks? Any additional insights regarding the $1 billion decrease in capital expenditures would be appreciated.

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, you're correct, the fourth quarter was a strong one for us, exceeding 13 million barrels per month, which included both propanes and butanes. We benefited from several factors, notably the export expansion project that enhanced our refrigeration capacity and allowed us to load vessels more quickly. We were able to operate throughout the entire fourth quarter, which contributed to our performance. Additionally, the nighttime transits introduced by the Houston Ship Channel and the collaboration with the Houston pilots provided another advantage. As a result, Targa experienced a benefit of about 5% to 10%, though it's challenging to quantify precisely due to multiple influencing factors. Furthermore, we took advantage of spot activity related to these increased liftings. I would like to extend my gratitude to the Houston pilots and the Houston Ship Channel for implementing nighttime transits safely and efficiently, which not only aids Targa but also supports various industries along the Houston Ship Channel, contributing to the Texas and U.S. economies. Looking ahead to 2024, you’re right in saying it's currently seen as a trial period. However, given the success and safe operations observed, we view this as a long-term change that will continue to benefit us. We aim to explore more ways to optimize our operations as we gain more insights from the nighttime transits and the vessels involved.

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

In the fourth quarter, the nighttime transits were not part of the entire period, as they were only implemented in November. We hope to identify better ways to optimize this process as we gain more insights into the program. It has already provided us with benefits, and we will continue to evaluate its performance going forward.

It's still early, Jeremy. I believe that a good range for potential upside right now is 5% to 10%, but we are still in the early stages.

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.

We feel very optimistic about our position as we transition from 2024 to 2025. I believe 2025 is shaping up positively, and we expect to see significant EBITDA growth not just in 2025 but also in the years that follow. This year, we have guided for a capital expenditure of 2.3 to 2.5 billion, which is slightly above last year's 2.2 billion. The investment multiple of about 5.5 times is an average over multiple years; it does not mean that spending a certain amount in a single year directly results in that year's EBITDA. We anticipate achieving around 5 to 6 times EBITDA on our capital expenditures. Considering our spending over the past couple of years, this positions us well for a strong performance in 2025. While we have chosen not to provide specific EBITDA guidance for 2025, our historical spending patterns and the positive trajectory of our overall volume across our operations lead us to believe that we are well-prepared for a successful year ahead.

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. To follow up on the long-term EBITDA growth outlook, you mentioned a build multiple around 5.5 times. A quarter or two ago, you noted that some of these projects came in at much lower multiples over the past three years. I'm trying to understand the difference there. Is there a sense of conservatism in the build, or does the commodity play a role in that? Additionally, could we potentially see some upside to the EBITDA build multiple? Thank you.

Sure, that's a good question. Historically, we've targeted a build multiple of 5 to 7 times. We've generally performed better than that, and the range was somewhat of a cushion. Over the last five years, we've been more around a 4 times build multiple. We've experienced strong volume growth in our system, and the Permian, Grand Prix filled up faster than we anticipated, which increased our returns. Our investment strategy this year and next is consistent with what we've done in the past, despite having a lower investment multiple. There may be a slight element of conservatism in that figure, but there isn't a significant difference due to commodity prices. We have more potential upside from commodity prices, considering the fee floors we've discussed, which could lower that multiple if we experience favorable commodity price trends.

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.

Thank you. To follow up on Spiro's question regarding the Permian and its growth, you previously mentioned a firm expectation of around 10%. Now, your illustrative guide indicates a high single-digit growth. Could you clarify if that's your baseline expectation at this stage? Additionally, do you have any updated insights on whether acquisitions in Midland are influencing your strategy? Regarding the operational challenges, have we moved past those? Also, how does your system handle H2S gas quality issues, and what allows you to potentially grow faster than the rest of the basin? Thank you.

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.

There's been significant M&A activity in the last few years, which we are well accustomed to. We don't perceive a substantial change with the recent announcements compared to previous ones. Growth across the combined companies has been fairly consistent when compared to the individual companies. We have strong positions and long-term contracts with all parties involved, along with excellent relationships with their producers. Based on what has been publicly disclosed, we don't anticipate a major impact on their expected growth levels. In fact, with one of the larger mergers, we might even expect some additional growth from our assets in the Midland region.

We are investing heavily in additional treating facilities, primarily in the Delaware Basin. We are adding more treaters to manage both CO2 and H2S, and we are drilling multiple gas injection wells along with pipelines and connectivity to support that. This positions us well as the Delaware continues to expand and as gas quality presents more challenges for producers. We will be well-prepared to manage those issues, with most of our capital investments expected to be in place by the end of this year.

The last part of your question was about whether volumes had rebounded after the winter storm. I’m really proud of our operations teams for their efforts to restore volumes. We are close to returning to the levels we saw before 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?

As we look ahead to 2024 and into 2025, we're placing orders for long lead items and budgeting for spending on Train 11, which will span both years. We're also considering additional plants, potentially one in Delaware and another in Midland, which will require long lead orders as part of our basic budget assumption. We anticipate needing to start capital expenditures in 2024 and 2025. If there's increased production growth in the Permian, it may accelerate the timing for these plants, but if growth is on the lower end, we may delay them slightly. The greater sensitivity in our capital expenditures typically lies on the downstream side. We need to consider when the next fractionator will be necessary and the implications of Daytona coming online, which should improve our NGL position. However, we also have to think about when we will need additional transportation and export capabilities, as those larger projects can be more volatile. Therefore, much of the variability in 2025 will likely revolve around our Gathering and Processing (G&P) business and the timing of plant projects and related field capital.

Super helpful. Appreciate it, Matt. Just a quick follow-up regarding the 90% fee-based. It's a significant shift from 2023. Clearly, this is a multiyear priority for your team and has been a gradual process. Are you seeing a notable change in 2024 primarily due to the mix? Which of your producers are experiencing growth? Did you observe significant re-evaluations or renegotiations happening throughout 2023?

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 over time, 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 over time.

This is Jen. It's a combination of factors you've mentioned, but for distinct reasons. The proportion of our gathering and processing business that is fee-based has increased significantly due to acquisitions. When we acquired Lucid, the contracts we obtained were mainly fee-based, leading to a substantial rise in fees from our gathering and processing business linked to that acquisition. Our commercial team has worked exceptionally hard to illustrate to producers the need to incentivize Targa to invest capital. This effort has been ongoing since 2020 and has gained momentum over the years. To ensure Targa is willing to continue investing capital, we have consistently aimed for an adequate rate of return even in a declining commodity price environment. Our producers have supported this approach. We’ve restructured existing contracts to include fee floors, which have encouraged us to keep investing even when commodity prices drop, while still allowing us to benefit if prices increase. So, we have acquired many fee-based assets on the gathering and processing side and either restructured existing contracts or established new ones with fee floor structures, all while delivering returns across our integrated system. The commercial team has excelled in supporting our producers’ needs while maintaining a framework that allows us to continue to invest 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?

Certainly. The main difference between the 1.4 and 1.7 is due to increased spending in our downstream operations, particularly with multiple fractionation facilities, which is more relevant this year. Most of the difference is related to downstream activities. One of the larger projects with no significant spending next year is the transportation of another NGL pipeline. We expect Daytona to come online this year, which should give us a solid opportunity. How much this opportunity yields depends on the overall growth rate in the Permian and our ability to capture those NGL barrels for transportation via Daytona. We also anticipate that building these pipes will take a couple of years, possibly longer. We need to plan for two to three years out to consider when we should think about looping the 30-inch segment. Additionally, there are transport options available through some competitors, which means we plan to move a large portion of our volumes through our own pipeline, but transportation agreements with competitors are also an option. Ultimately, we are keeping all options open, whether it involves constructing a 30-inch pipeline in the future or making use of excess capacity from other NGL pipelines.

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 by noting that we currently use third-party pipes for the volumes coming into our Belvieu facility. As we look at growth in our G&P sector and the Daytona pipeline, we are not aggressively pursuing fees to fill our existing capacity and the expected capacity for Daytona. This aligns with the growth that Pat and his G&P team are experiencing in transportation. Matt mentioned that if industry pipes have available capacity, we can explore using them, as we do now, to bridge any gaps until we might need to loop around our current system. Regarding Galena Park, we have a solid understanding of what the next expansion project will entail, which includes factors such as adding refrigeration, pipes, potential docks, and similar elements. We're monitoring the timing of this in relation to our growth, primarily driven by our G&P business, and will continue to assess it. The expansion we completed in the fourth quarter has already started benefiting us, particularly with nighttime transits, and these projects are progressing without significant capital expenditure. We'll keep seeking opportunities to optimize capacity as well. Overall, there is considerable potential and space available for expansion at Galena Park with our existing assets.

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 currently uncertain whether we will be subject to the AMT in 2026 or 2027, as it's quite close. We want to provide a conservative estimate based on our latest forecast indicating that we might be subject to the AMT. In 2027, we would have fully utilized our net operating losses and would be fully subject to the statutory tax rate. If the current bill passing through Congress includes a return of accelerated bonus depreciation, that would significantly benefit us and could delay our timeline by about a year, based on current forecasts. Ultimately, we will need to see the final policy that is enacted, but this is our initial assessment at this point.

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 onto 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 a 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.

We experienced some challenges last year due to delays in our compression projects. A significant amount of compression came online late last year, which helped increase our volumes in the fourth quarter. Currently, we have an additional $400 million earmarked for compression and have been proactive, placing orders for compressors a year in advance to avoid falling behind. Recently, we approved another order for inventory to stay prepared for 2025. However, the success of this plan is dependent on volume growth. If volumes exceed our projections, we might encounter some challenges. We are doing our best to analyze the forecasts and stay ahead of demand.

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.

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.

We are actively exploring all avenues to transport gas out of the basin, which includes the Apex project. We have consistently emphasized that our top priority is ensuring that gas flows from the basin so that NGLs can be processed at our facilities and transported down the Grand Prix and across our docks. In my last call, I mentioned the emergence of several other projects that align with our requirements, and we are diligently pursuing those alongside Apex. Each month, I become more optimistic about our efforts to establish a pipeline that is expected to be operational around 2026. I am confident that progress will be made this year, whether it involves Apex or one of the various options we are considering to enhance gas transport out of the basin.

In regards to the CapEx, that figure of 1.4 does not include it. For any project, we will assess whether it makes sense for us to be involved as a partner, which could increase that CapEx. Additionally, some of these pipelines may be primarily financed through project financing, meaning any equity we contribute would be relatively small and it may not be project financed. However, that is not included 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 haven't established a specific date for the in-service timeline. By ordering long lead items, we gain some flexibility regarding when that will occur in the future. However, we're encountering some challenges due to supply chain issues with certain equipment. Consequently, we can allocate a small amount of capital to ensure we can meet whatever date we announce in the future. Although we don't have a defined date at this moment, it's certainly a priority for us to monitor and stay 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.

This concludes today's conference call. Thank you for your participation. You may now disconnect.