Targa Resources, Inc.

At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Sanjay Ladd, VP of Finance and Investor Relations. Please go ahead.

Thanks, Gigi. Good morning and welcome to the third quarter 2022 earnings call for Target Resources Corp. The third quarter earnings release along with the third quarter earnings supplement presentation for Target Resources that accompany our call are available on our website at TargetResources.com in the investor section. In addition, an updated investor presentation has also been posted to our website. Statements made during this call that might include target resources, expectations, or predictions should be considered forward-looking statements within the meaning of Section 21E of the Security Exchange Act of 1934. Actual results could differ materially from those projected in forward-looking statements. For the discussion of factors that could cause actual results to differ, please refer to our most recent annual report on Form 10-K, and latest SEC filing. Our speakers for the call today will be Matt Molloy, Chief Executive Officer, Pat McDonnie, President, Gathering and Processing, Scott Pryor, President, Logistics and Transportation, Robert Moraro, Chief Commercial Officer, and Jen Neal, Chief Financial Officer. I will now turn the call over to Matt, who is recovering from laryngitis, but his comments and Q&A participation today will be limited.

Thanks, Sanjay, and good morning. And apologies for my hoarse voice. Our overall business is continuing to perform well, and our strong execution continued across the third quarter, including record high quarterly EBITDA, record volumes in the Permian, record NGL transportation and fractionation volumes, integration of our Delaware Basin acquisition, successfully bringing on two plants in the Permian basin safely ahead of schedule and on budget, 73 million of opportunistic common share repurchases, and we were also recently added to the S&P 500. Our record third quarter EBITDA was attributable to higher base business volumes, particularly in the Permian, plus a partial quarter contribution from our Delaware basin acquisition. While commodity prices are significantly lower than the assumptions underlying the updated full-year 2022 financial expectations that we provided in early August, there is no change to our expectation to generate full-year adjusted EBITDA between $2.85 billion and $2.95 billion. Given the significant growth in volumes that we expect looking forward and to catch up on some of our Delaware Basin infrastructure, We announced this morning that we are moving forward with a new 275 million cubic feet per day gas processing plant in the Permian, Delaware, which we are calling the Wildcat II plant. The growth in volumes across our GMP business also necessitated the announcement this morning that we are kicking off construction of the Daytona NGL pipeline, which will transport volumes from the Permian Basin and connect to our existing segment of Grand Prix in North Texas to move volumes down to Mont Bellevue. The acceleration of these additional projects shifts some spending into 2022, but there is no change to our year-end 2022 leverage ratio expectation of about 3.5 times, meaning we continue to have significant financial flexibility looking forward. Before I turn the call over to Pat, I would like to extend a thank you to our employees for their continued focus on safety while executing on our strategic priorities and continuing to provide best-in-class services to our customers. I will now turn it over to Pat to discuss our GMP operations in more detail. Pat?

Thanks, Matt, and good morning, everyone. Starting in the Permian, our systems across the Midland and Delaware Basins average a record 4.1 billion cubic feet per day of report inlet volumes during the third quarter, including two months of contribution from our recently completed Delaware Basin acquisition. Given our performance year to date, we expect our full year average 2022 Permian volumes, not including our Delaware Basin acquisition, to increase at the high end of our initial 12 to 15% year-over-year volume guidance. In Permian Midland, our inlet volumes increased 8% sequentially as our system essentially ran at capacity until our new legacy plant came online late in the third quarter. We have an incremental 550 million cubic feet per day of processing expansions underway in Permian Midland. Our Legacy II plant remains on track to begin operations during the second quarter of 2023, and our Greenwood plant remains on track to begin operations late in the fourth quarter of 2023. Similarly, we expect both plants to be highly utilized when they come online next year. In Permian, Delaware, inlet volumes across our system, not including contribution from our Delaware Basin acquisition, increased 7% sequentially. We have successfully integrated our Delaware Basin assets and employees and appreciate the efforts of the collective target team that supported the integration. We commenced operations on our new 230 million cubic feet per day Red Hills 6 plant in late September, which was full at startup. Our overall Delaware system is also running very highly utilized and volumes continue to ramp. and we remain on track to bring our new 275 million cubic feet per day midway plant online during the second quarter of 2023. In response to strong producer activity levels and to meet the infrastructure needs of our customers across the Delaware, and as Matt previously mentioned, we are moving forward with the construction of a new 275 million per day plant in Permian, Delaware, which we are calling the Wildcat II plant. Wildcat 2 is expected to begin operations in the first quarter of 2024. We are playing some catch-up on our newly acquired Delaware Basin assets, as evidenced by Red Hill 6 being full at start of, the expectation that Midway will be highly utilized on start of, and now moving forward with construction of the Wildcat 2 facility. All a positive reflection of how quickly current volumes are increasing and future volumes are expected to increase. We are also adding incremental treating infrastructure in the Delaware to increase our sour gas handling capabilities, which enhances our ability to capture and handle increasing sour gas production and drive attractive returns from treating fees. This will also give us the ability to capture CO2 from the treating process and sequester the emissions in our acid gas injection storage wells. We have already obtained Class 2 permits and are working on MRV plans and additional Class 2 and Class 6 permits to further enhance our carbon capture abilities. We expect to begin receiving 45Q tax credits as early as the fourth quarter of 2023. Shifting to the Badlands, our natural gas and crude gathered volumes rebounded in the third quarter, following the reduced reported volumes that were impacted by late winter storms in the prior quarter. In our central region, a full quarter contribution from the acquired assets in South Texas and solid activity levels in Oklahoma and North Texas drove a sequential increase in aggregate volumes during the third quarter, partially offset by a contract expiration in South Oak. Scott will now discuss our logistics and transportation business in more detail. Scott?

Thanks, Pat. Target's NGL transportation volumes were a record 500,000 barrels per day. Fractionation volumes were a record 742,000 barrels per day during the third quarter. Our volumes would have been higher had it not been for some ethane rejection across our system and third-party systems during the third quarter, plus some maintenance at our Mount Bellevue facility. Given the anticipated volume growth from our Permian GMP expansions, growth of third-party volumes and volumes we can transport after the expirations of obligations on third-party pipelines, our outlook for continued NGL transportation volume growth is strong. Today, we announced plans to construct the Daytona NGL pipeline to transport NGLs from the Permian Basin and connect to the 30-inch diameter segment of the Grand Prix NGL pipeline in North Texas. Daytona is expected to be in service by the end of 2024. Targa will own 75% of Daytona, and Blackstone Energy Partners will own 25%, with each member funding the respective share of the pipeline's costs based on their ownership percentage. With an estimated project cost of about $650 million, Targa's net growth CapEx share is estimated to be approximately $488 million. In Mount Bellevue, construction continues on our Train 9 fractionator, which is expected to begin operations during the second quarter, of 2024 with an estimated cost of around $450 million. Turning to our LPG exports, we loaded an average of 8.5 million barrels per month during the third quarter as we were impacted by reduced spot cargo opportunities and some cancellations due to weaker global market conditions. We currently expect fourth quarter volumes to improve, but will be impacted by similar global dynamics and some required maintenance at the terminal. Our low-cost LPG export expansion project to increase our propane loading capabilities with an incremental 1 million barrels per month of capacity remains on track for mid-2023. I'll now turn the call over to Jen.

Thanks, Scott. Good morning, everyone. Our record quarterly adjusted EBITDA and operational stats reflect that our business is performing really well. Our balance sheet is strong. We are continuing to invest in our business. We are returning an increasing amount of capital to our shareholders, and we are very excited about Targa's outlook. Let's now go over some additional financial information. Targa's reported quarterly adjusted EBITDA for the third quarter was $769 million, increasing 15% sequentially as we benefited from a partial quarter contribution from our Delaware Basin acquisition, higher volumes across our gathering and processing and logistics and transportation systems, and higher fees. partially offset by lower NGL prices and higher operating expenses. Higher operating expenses were primarily attributable to our recent Delaware Basin acquisition, increasing activity levels across our GMP systems, including two plants placed in service in the quarter, and inflation. While costs were higher, just a reminder that for Targa, inflation is a net tailwind across our businesses, as we benefit from inflation-linked fee escalators across our commercial contracts. Target generated adjusted free cash flow of $291 million in the third quarter. We repurchased about $73 million of common shares in the quarter, and year-to-date through September 30th have repurchased about $197 million of common shares at a weighted average price of $65.23. Since program inception, we have repurchased about $328 million of shares at a weighted average price of $35.45. As of quarter end, we had approximately $172 million remaining under our $500 million equity repurchase program. For the third quarter, we declared a cash dividend of $0.35 per common share or $1.40 per share on an annualized basis, and consistent with previous messaging, expect to maintain the same dividend for the fourth quarter. Looking ahead, we currently plan to provide our full year 2023 operational and financial outlook in February in conjunction with our fourth quarter earnings call, and we'll also then provide color on our expected annualized dividend and share repurchase strategy for 2023. We are well hedged for the fourth quarter looking forward, We are currently about 80% hedged in 2023 across all commodities related to our exposure from our percent of proceeds contracts and are hedged at higher prices in 2023 than 2022 hedge prices. As Matt mentioned, our performance this year has been strong, and we continue to estimate our leverage ratio will be around 3.5 times at year end. During the third quarter, we upsized our accounts receivable securitization facility to $800 million and extended the facility to September 1, 2023. We spent about $625 million of net growth capital through the first three quarters of 2022. With some additional spending accelerating into 2022 for the Wildcat II plant and the Daytona NGL pipeline announced today, We now estimate 2022 net growth capex to be between $1.1 billion and $1.2 billion. Our estimate for 2022 net maintenance capex remains unchanged at approximately $150 million. We have strong momentum heading into 2023, backed by continued volume growth across our integrated businesses, and we expect to benefit from full-year contributions from our Delaware Basin and South Texas acquisitions, higher fees, and higher hedge prices. We are focused on continuing to manage our leverage ratio within our three to four times long-term target range, with a preference to be in the lower half of the range, and believe that the strength of our underlying business puts us in excellent position over the long term to continue to invest in attractive organic growth opportunities and return an increasing amount of capital to our shareholders. We published our 2021 sustainability report in early October and kicked off an initiative that is very important to us, where we engage with our largest shareholders each fall specifically around ESG to get feedback on our latest report and ESG-related efforts. We take our responsibilities seriously and are committed to practices that create value for our shareholders and benefit the communities we serve, and our latest report is hopefully reflective of that commitment. Lastly, I'd like to echo Matt and thank our employees for their dedication and for continuing to prioritize safety. 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 re-enter the line-up if you have additional questions. Gigi, would you please open the line for Q&A?

As a reminder, to ask a question, you will need to press star 1-1 on your telephone. Please stand by while we compile the Q&A roster. Our first question comes from the line of Colton Bean from Tudor Pickering Holt and Company.

Morning. So just starting off on Grand Prix, is there a general capacity buffer that you all were targeting when deciding when to bring Daytona into service? I guess asked differently, is there any risk of constraint on targets in GL egress if Daytona timing were to slip a quarter or two?

Hey Colton, this is Scott. We've obviously been watching our volumes as it relates to Grand Prix, both on the west leg and the north leg that feeds into Mount Bellevue for some time now. And clearly watching the cadence of the plants that we've been adding on the GMP side of our business and along with the Delaware acquisition that we made. So we are keenly aware of the volumes that are moving and the timing of announcing Daytona fits with our expectations. We feel very comfortable with the fourth quarter, operating that startup in fourth quarter of 2024. Again, with Daytona, when you look at the volume growth that we've got from our GMP business, third-party volumes, expirations of third-party pipe volumes over time, it's a very good project for us. Especially, it leverages the capacity that we've got available on our 30-inch pipeline that feeds into Mount Bellevue. that it gives us plenty of room over a period of time. I'd also like to state that when we start up Daytona and how it complements our Grand Prix West leg, we'll also get some efficiencies on the fuel side of things as we operate. It allows us to better operate pumps that are along the existing West leg in addition to how we would operate the pumps on the Daytona side.

Great. And Jen, maybe pivoting over to hedges, I think you mentioned being above the normal course, 75% for 2023. Can you expand on where you sit for next year and just the broader thought process on going above your programmatic level?

I think based on the view that we had that there was likely to be Waha tightness and potential impacts on prices on the Waha side, we've added additional hedges, particularly around natural gas, Colton. So we're hedged above the 75% level on natural gas, actually significantly higher hedged than that right now for 2023. Then on the NGL side, we're a little bit higher hedged than the 75% level, just continuing to watch backwardation of NGL price markets. And to the extent that we get strength, we have tried to hedge into some of that strength. And then we've got a little bit of condensate exposure in our well hedged there, well north of that 75% level too. And those hedges are all related to our percent of proceeds contracts. So we do have commodity exposure elsewhere in our business, but have tried to do a very good job of hedging in advance of 2023 to help underpin continued cash flow stability across our businesses.

Great. And it sounds like on natural gas, the hedges also include an attempt to reduce basis risk.

Yes, we hedge directly to our basis points and certainly have tried to be far in advance of any price risk around Waha in 2023. Our gas marketing team has done a really good job of trying to manage not only takeaway transport, but also our hedge exposure there.

Great. I appreciate the time.

Thank you. One moment for our next question. Our next question comes from the line of Jeremy Tonnet from JP Morgan.

Hi. Good morning.

Good morning, Jeremy.

I just want to kind of walk through, I guess, the results this quarter, because if you look at the last guide and we overlay kind of the commodity prices, how they changed and what your sensitivities were, it seemed to put some pressure on EBITDA expectations for the year, possibly below the bottom end. Yet you were able to reaffirm the guidance range. So it seems like some positives, you know, materialized versus, I guess, prior expectations there. Just wondering if you could provide a bit more detail on what those were and if you see them continuing into 2023.

I think that we have a pretty good track record of forecasting guidance conservatively, Jeremy, which is part of it, but also the underlying business is just performing really, really well. So when we think about the volume increases that we're seeing across our systems, it feels like every quarter we're reporting record Permian volumes, even ignoring the acquisition of the Delaware Basin assets, which will bring significantly more volume to our system, and then on the transportation and fractionation side as well. So while prices were weaker in the quarter, we're comfortable with where our guidance is set right now for the rest of the year. We've got only two months to go. And again, think that the business is performing so well that we're really setting up nicely heading into 2023 as well.

Got it. That's helpful there. And then Looking at 23 and recognizing the guide is not coming until February, but just wondering if you could provide any high-level thoughts as far as capital allocation is concerned, where CapEx could shake out and how you think about the best way to return capital.

I think 2022 provides a little bit of a roadmap for how we're thinking about returning capital to shareholders. We entered 2022 focused on managing our leverage to levels that we are comfortable with, and then also simplifying and also continuing to invest in the business and returning capital to shareholders. And I think that we've been able to execute across all dimensions in 2022. So for 2023, thankfully, we've got the simplifications behind us. No more devcos, no more prefs. And so it really allows us to focus on maintaining that balance sheet strength that we've spent so much time over the last several years talking about, and then continuing to invest in our business, additional organic growth capital opportunities that are very attractive for us like Wildcat II and like Daytona and like all the other projects that we have in progress, and then continuing to return an increasing amount of capital to our shareholders through a higher dividend and additional share purchases. So I think it will be a similar roadmap in 2023, and we look forward to describing that in February. On the growth capital side, There's some lumpiness just related to the types of projects that we spend capital on. So when you think about Daytona and Wildcat II, a little bit of capital accelerating into this year. But a lot of capital on both of those projects will be spent in 2023. And then there's still lumpiness around Train 9 spending. So there's significant Train 9 spending in 2023 as well, along with just the natural cadence of plant ads, compression ads, and gathering line ads. So 2023 capital will be higher and we'll give more visibility to that in February as well, but certainly we're very comfortable and believe that similar to our spending this year underpinning EBITDA growth 23 over 2022, the spending that we'll be doing next year is what will set us up for continued EBITDA growth going forward as well.

That's very helpful. I'll leave it there. Thanks.

Thank you. Thank you. One moment for our next question. Our next question comes from the line of Brian Reynolds from UBS.

Hi, good morning, everyone. Maybe just to circle back on Lucid, could you just talk a little bit about the synergies seen so far to capture, you know, some of those offloaded volumes? You know, curious if you can just talk about how the transaction multiple is being worked down, perhaps before all of the Lucid volumes, you know, fully work its way through the target integrated system in a few years. Thanks.

Yeah.

You know, Red Hill 6 came on in September. It's full. Frankly, volumes were greater than the capacity of the system, including Red Hill 6. So immediately what we were able to do is offload some of the gas on the Lucid system into our western Delaware plants, which had spare capacity. Pretty significant volumes, frankly. Lucid was in the process prior to us acquiring them you know, seeking out offloads. We had some in place with them already, and certainly upon completion of the acquisition, we stepped that up considerably and are building additional infrastructure that allows better communication between the, what we call Target North Delaware system, the old Lucid assets, and our existing Delaware footprint. So the integration has gone pretty seamlessly. The volume growth is substantial, so... we can get it done, the better. But we're definitely seeing benefits of the integration and we'll see additional benefits via some of the projects that we've announced this morning.

Great. I appreciate that. You know, as my one follow-up, since we're excited with entering 2023, just given some operational issues from some peers, there's various projects that are coming online in 2020. Three, but curious if you could talk about the GCF frack and un-IO link or if there's any desire to simplify that JV over the next year or two. Thanks.

Hey, Brian. This is Scott again. We are evaluating with our partners at GCF, recognizing that is in a partnership as to what the timing would be of moving that from an idled asset to an operating asset. So we don't have a definitive date at this point, but the discussions are happening and just trying to understand what the volumes look like for not only Targa, but respectively also for our partners in that. With that said, obviously we are moving forward with our Train 9. That would be operational in the second quarter of 2024. And in addition to that, we also have a permit in hand for our Train 10. So as we continue to evaluate the build-out of our GMP footprint, how that feeds into our Grand Prix system, the expansion with Daytona, and those deliveries into Mount Bellevue. Determination of when we would start a Train 10 or restart a GCF asset will be certainly taking all those volumes into consideration.

Great. Super helpful. Enjoy the rest of your morning, everyone. Thanks, Brian.

Thank you. One moment for our next question. Our next question comes from the line of Keith Stanley from Wolf Research.

Hi. Good morning. Wanted to start a couple quick follow-ups on Daytona. Should we assume a pretty even split on the CapEx between 2023 and 2024? And did you say the capacity of the expansion? I think previously you talked to maybe 550,000 a day.

Keith, this is Jen. In terms of spending, we've got a little bit that's coming into 2022, and then we'll have spending, of course, in 23, and actually more in 24 than in 2023 is what we currently have forecasted, but we're trying to get Daytona online as quickly as possible. So that may shift between 23 and 2024, but that's what the spending currently looks like right now.

And then as it relates, Keith, to the volume expectations, when we start up Daytona, it'll have an initial capacity of about 400,000 barrels a day. And just as a reminder, our current West Grand Prix leg has a capacity of roughly 550,000 barrels a day. So they will complement each other very well. And again, as I stated earlier in our comments, we would operate those two lines together in order to get fuel efficiencies across both lines.

Thanks for that. My second question is on Permian Gas. I guess first, I'm just curious how, if you have a view on how much of the weakness we've seen this fall has been due to maintenance versus a tighter than expected market, and any updated thoughts on the potential to support a new takeaway project, either through contracting or ownership, and when we might hear more on that.

This is Bobby. I tell you, I think it's a combination of a lot of things at the end of the day. You have, I think, better production than some people have forecasted, and then more maintenance than everyone had planned for, along with some pipelines still being out relative to El Paso going west out of the basin. So I think from that perspective, it's all kind of intersected at a point where you saw some extreme weakness when multiple pipes went down. At the end of the day, I think a big help would be El Paso coming back online, and then as the PHB and Matterhorn expansions come online, or the PHB and Whistler expansions come online, sorry, and then Matterhorn comes online in 2024, I think we'll see the base can get a lot better. I think we have spent a lot of time preparing for that. Our group has been through this before, and I think we see a line of sight to target being able to operate all our assets at the capacities we have. we will need through that period of time. As for TARGA and long-haul gas pipelines, we want to see them built. We'll keep saying that. We'll always say that. If it takes us participating, we're always willing to participate. If other people get them done and gas gets out of the basin and flattens out basis, we're excited to see that too. So I think we always stand by and stand ready for what's needed because what we want to see is the gas flows so that our plants keep operating and our NGLs go through our system. Thank you.

Thank you. One moment for our next question. Our next question comes from the line of Theresa Chen from Barclays.

Hi there. I wanted to ask on the comments related to the carbon capture opportunities and your anticipation of receiving 45Q credits soon. Can you provide some more detail on the nature of the economics with these projects in general and your outlook from here?

So I think, this is Bobby, sorry. We look at them like we do our kind of traditional economics around the rest of our system. So it's not that we have specific hurdles, but we have thresholds of which the team here wants to invest capital in projects. And what I tell you is in looking at our carbon capture projects prior to the updated 45Q, they were economic. And as we get to the new and better 45Q, credit that we will get and makes them that much better. So we don't comment on specific projects and specific returns, but these projects went from economic, in our view, under traditional ways we run economics, to just that much better when the new 45-2 came out. And so it's kind of, I won't say it's accelerated our thinking, but it makes us more intentional about making sure we get all these done.

And then related to timing, Teresa, we said in our scripted comments that we thought that We could start getting credits as early as Q4 of 2023.

Got it. And in relation to your LPG exports, just curious as to why you have confidence that it will rebound and get better in the fourth quarter, just given the pervasive downstream headwinds at your customers, both Asia and Europe, I imagine. And then also, can you remind us, you know, around what percentage volumes do you have currently contracted at this point?

Hey, Teresa, this is Scott. First off, just to reiterate, our volumes were 8.5 million barrels per month during the quarter. That was down, obviously, from what we saw in the second quarter. But it was comparative to what really the industry saw as a whole, roughly down about 15% quarter over quarter when you look at the exports out of the U.S. to various markets across the globe. A lot of that was driven by just, as you stated, weaker global markets. Some of that related to Asian ethylene producers, where they were faced with really some unattractive economics relative to the co-products and products they produce on that side of the business. and thus they cut some of their LPG usage as a result of that. We also saw some slowdowns in China due to some areas that may have been impacted by COVID shutdowns and things of that nature, which slowed up some of the PDH plant activity. But in general, I would say the reason why we feel as though the volumes would look better in the fourth quarter is because where we sit today, what has been lifted thus far, what is on our schedule for the balance of the fourth quarter, that's why we feel comfortable stating that our volumes will be up in the fourth quarter. With that said, we're still going to be facing some global market issues that are weaker at this point, shipping issues and things of that nature, as well as conducting some scheduled maintenance that we need to do in the fourth quarter. But again, overall, we would believe at this point that our volumes will be up in the fourth quarter.

Thank you. Thank you. Thank you. One moment for our next question. Our next question comes from the line of Sunil Sebal from Seaport Global.

Yes, hi. Good morning, everybody, and thanks for all the clarity. So when I look at the base GNP business, obviously it seems like you have some impact of the inflation on your fees as well as on your OPEX. So I was just curious, you know, from here on, should we consider that, you know, most of those inflation adjusters have kicked in and that, you know, are incorporated in the 3Q results, or should we expect, you know, any significant moments in that?

Danil, this is Jen. I'd say that across our entire portfolio of contracts, most of the escalators have kicked in for this year. We've talked previously about the fact that we have a number of contracts that essentially kick in January 1st, then a number of contracts that kick in mid-year, and then there's some others that I'd say is more the minority that kick in on the annual renewal date of the contract or based on some other date during the calendar year. So, yes, I think it's fair to say that we have benefited from the escalators that we would expect this year, and then heading into 2023, of course, we'll be a net beneficiary of escalators as we move forward through into next year.

Got it. And then, could you give us a sense of, you know, at-end projection across your Permian footprint and, you know, what trends do you expect to play out in the near term on that?

I'm not sure I fully heard the question.

At-end rejection in the Permian.

Yeah, the natural gas takeaway situation is going to play into that pretty heavily, right? If you can't move residue gas, then probably more barrels are going to be pulled, more is going to be recovered than rejected. incremental MMBTUs into a tight gas market is going to be problematic. So I think, one, first, it's always an economic decision, and it will continue to be an economic decision. And then some of those other dynamics relative to the ability to move residue gas, and, you know, obviously if that price gets really low, which we've seen recently relative to ethane price, I think you'll see recoveries in ethane being transported to Bellevue. Okay, got it. Thanks.

Thank you. Thank you. One moment for our next question. Our next question comes from the line of Neil Mitra from Bank of America.

Hi, good morning. Just had a few follow-ups on Daytona. First, is it going to twin Grand Prix or are you going to maybe have it go a different direction in some places so it can access new processing facilities? And then the second part of that is, is it limited to 400,000 cubic feet a day because of the limitation on the 30-inch pipe from North Texas to Mount Bellevue?

Hey, Neil, this is Scott Pryor. First off, I've The way you need to view Daytona is basically a loop of the existing Grand Prix West leg, albeit we will be taking advantage of the lines that move further west, both in Texas as well as into New Mexico. That Grand Prix system today will help feed both the Grand Prix West as well as the Daytona system. So it will run virtually parallel. of the Grand Prix West system tying into our 30-inch leg in North Texas, what we refer to as our junction point, which is just south of Dallas, Texas. It allows us to leverage capacity that we have on the 30-inch pipeline, and when we say that it has an initial capacity of 400,000 barrels a day, it's similar to how we said Grand Prix West had initial capacity of roughly 400,000 barrels a day when it first started up, but we have put pumps on to amp that up to call it 550,000 barrels a day. We would have the same ability to do that with Daytona. So we're taking advantage of where all of our plant activity is in the Permian. So it will have the ability to, again, feed both Grand Prix West as well as Daytona. take advantage of that line out of North Texas feeding into Mount Bellevue. So it lines up very well with where our concentration of plant activity is.

And if I could just follow up on that, it seemed like 950, is that the limitation from North Texas to Mount Bellevue, or could you get more capacity with pumps?

Yeah, we have... had a cadence of where we've been putting on pumps, both on the west leg as well as the south leg, to complement the volumes that are coming from west as well as in north Texas and up into Oklahoma. I would call it nominally a million barrels per day of capacity on the 30-inch leg going into Mount Bellevue.

Okay, great. And then just the second question, it seems like you've had some commercial success, Wildcat II and Winkler II, Wildcat plant you brought on in the last four years and the Legacy Delaware. Could you just comment on the customer mix or private publics and activity you're seeing in that area to cause you to go forward with that project?

Sure. It is a mix, as you described. We have a big chunk of the majors' dedication on both of those systems. And certainly, if you think about the Delaware Basin, there's been acquisitions recently by majors that have gobbled up some of the smaller guys. So that is added to their portfolio, which is dedicated up under us. And then we have a ton of mid to smaller guys that are extremely active, some of which we've done business with a long time and some of which, as you described, we've had commercial success with and added to our portfolio.

Okay, got it. Thank you very much.

Thank you. One moment for our next question. Our next question comes from the line of John McKay from Goldman Sachs.

Hey, all. Thanks for the time. I wanted to pick up on that last piece. You guys are showing really a much better volume outlook than a lot of your peers on the midstream side are talking about, and we've seen a couple of the producers starting to slow down. I'm just wondering if you could spend another minute maybe just talking about kind of what's differentiating your footprint, what kind of, you know, giving you guys a confidence on the growth outlook and whether or not you have seen, you know, a little bit of slowdown from your producer customers.

I'll address the last part first. This is Pat McDonough. We really haven't seen an appreciable slowdown. The people that have employed rigs continue to employ them and just move them across their acreage and continue to drill. Certainly we've been fortunate that a lot of those rigs are running on our acreage, but I would tell you that our infrastructure underpins a lot of the best acreage in the Delaware Basin and also obviously in the Midland Basin as seen by many years of history. You've seen the Exxons, the Chevrons, the big guys come out and announce what their plans are for next year, and there's no appreciable slowdown from them. Just their public information is available, and Chevron's actually adding rigs. Our smaller guys, the economics are very good, and they continue to stay active. So we have not seen a slowdown. There certainly has been some logistical constraints that you know, have at times made duck ponds a little bit lumpy, in other words, you know, waiting on completion crews, et cetera, but the wells are still getting drilled, eventually getting completed. So I can't speak to our competitors or our peers, but certainly we're seeing a continued level of high activity.

I appreciate that. Maybe picking up on that, on one comment from earlier too, I think Teresa's question, just back to the exports. Have you guys commented on what your contracted levels are?

John, I'm sorry. We could not hear a word of that.

I'll try again. Just circling back to Teresa's question on the exports. Have you guys commented where your current contracted levels sit?

I'm sorry, John. We couldn't hear a word of that either. I'll follow up offline. Okay. We'll follow up offline. Perfect.

Thank you.

Sorry about that.

Thank you. One moment for our next question. Our next question comes from the line of Michael Cusimano from Pickering Energy Partners.

Hi. Good morning. I just have a few follow-ups from some of the questions that have been asked. First, Jen, I appreciate the help on the hedge exposure. Specifically in regards to WAHA, though, should we think about any weighting throughout the year for how those hedges are on? I guess I'm thinking of the first three quarters more heavily weighted for that basis diff than the back, you know, fourth quarter. And is that 80% an annual average?

The percents that I gave would be annual averages for next year, Michael. And then the way that we generally hedge is there can be some shaping where there's more hedged earlier in the year than later in the year. But I'd say that for next year, it's actually all pretty rateable at this point in time on the gas side.

OK. That's helpful. And then on the SA rejection that you experienced, is it fair to assume that that was in the mid-con with the volumes a little bit lower, quarter to quarter. And then to follow on for that, can we assume that the west leg of the Grand Prix line grew similar to what volumes did? Just how do we think about that?

This is Jen. Related to the mid-con, we actually had a contract expiration that we called out in South Oak. And so that's part of what resulted in the volumes there being lower quarter over quarter. it was really in the Permian and a little bit elsewhere that we were making decisions around rejection recovery based on what we were seeing related to some of the maintenance issues on certain pipes and pricing around natural gas and ethane.

Okay, got it. And then lastly, can you remind us the typical cadence spend for just your standard processing plant? You know, if it's a four quarter lead time, how that typically looks and if there's any nuance to the ongoing processing plants that you're working on?

It depends. Each plant is a little bit different based on whether there's additional treating infrastructure or what else is required if it's plumbed close to existing infrastructure or not. So again, each plant is a little bit different. I'd say that generally the spend is across the life of the project prior to it coming online. So there isn't significant lumpiness for Wildcat 2, for example, that would be hitting this quarter, but then as we move into 2023, you wouldn't see continued spending. So I'd say that for modeling purposes, it's easiest and probably most accurate just to assume rateable spending from now until a project comes online.

Okay. That's really helpful. That's all for me. I appreciate the help.

Thanks, Michael. Thank you. I would now like to turn the conference back over to Sanjay Ladd for closing remarks.

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

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