Targa Resources [TRGP] Conference call transcript for 2022 q3
2022-11-03 16:33:06
Fiscal: 2022 q3
Operator: Good day, and thank you for standing by. Welcome to the Targa Resources Corp. Third Quarter 2022 Earnings Webcast and Presentation. At this time, all participants are in a listen-only mode. After the speakersâ 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, VP of Finance and Investor Relations. Please go ahead.
Sanjay Lad: Thanks, Gigi. Good morning, and welcome to the Third Quarter 2022 Earnings Call for Targa Resources Corp. The third quarter earnings release, along with the third quarter earnings supplement presentation for Targa Resources that accompany our call are available on our website at targaresources.com in the Investors section. In addition, an updated investor presentation has also been posted to our website. Statements made during this call that might include Targa Resources' expectations or predictions should be considered forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our most recent annual report on Form 10-K and latest SEC filings. Our speakers for the call today will be Matt Meloy, Chief Executive Officer; Pat McDonie, President, Gathering and Processing; Scott Pryor, President, Logistics and Transportation; Robert Muraro, Chief Commercial Officer; and Jen Kneale, Chief Financial Officer. I will now turn the call over to Matt, who is recovering from laryngitis for his comments and Q&A participation today will be limited.
Matt Meloy: 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 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 G&P 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 and North Texas, to move volumes down to Mont Belvieu. The acceleration of these additional projects shift 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 G&P operations in more detail. Pat?
Pat McDonie: Thanks Matt and good morning everyone. Starting in the Permian our systems across the Midland and Delaware Basins averaged a record 4.1 billion cubic feet per day of 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 volume 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 two 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 Targa team that supported the integration. We commenced operations on our new 230 million cubic feet per day Red Hills VI plant in late September which was full at start-up. Our overall Delaware system is also running highly -- very highly utilized and volumes continue to ramp. And we remain on track to bring our new 275 million cubic 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 II 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 Hills VI being full at startup, the expectation that Midway will be highly utilized on start-up and now moving forward with construction of the Wildcat II 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 gas handling capabilities which enhances our ability to capture and handle increasing 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 II permits and are working on MRV plans and additional Class II and Class VI 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 backgrounds our natural gas and crude gathered volumes rebounded in the third quarter following the reduced reported volumes impacted by late weather 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 via contract expiration in South Texas. Scott will now discuss our logistics and transportation business in more detail. Scott?
Scott Pryor: Thanks Pat. Targa'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 Mont Belvieu facility. Given the anticipated growth from our volume growth from our Permian G&P 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% and with each member funding the respective share of the pipeline's cost 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 Mont Belvieu construction continues on our Train nine 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 core 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 one million barrels per month of capacity remains on track for mid-2023. I'll now turn the call over to Jen.
Jen Kneale: 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 G&P 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. Targa 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 30 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 will 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 responsibility 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.
Sanjay Lad: Thanks, Jen. For the Q&A session, we kindly ask that you limit to one question and one follow-up and reenter the line up if you have additional questions. Gigi, would you please open the line for Q&A?
Operator: Our first question comes from the line of Colton Bean from Tudor Pickering Holt & Co.
Matt Meloy : Good morning.
Colton Bean: 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 target NGL egress of Daytona timing were to slip a quarter or two?
Scott Pryor: Hi, 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 Mont Belvieu for some time now and clearly watching the cadence of the plants that we've been adding on the G&P 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 start in fourth quarter of 2024. And again with Daytona when you look at the volume growth that we've got from our G&P business, third-party volumes, expirations the third-party pipe volumes over time. It's a very good project for us. And especially it leverages the capacity that we've got available on our 30-inch pipeline that feeds into Mont Belvieu. So that 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 efficiency 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.
Colton Bean: Great. And Jen maybe commenting 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 doing above your programmatic level?
Jen Kneale: 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 are 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 they're well north of that 75% level to. 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.
Colton Bean: Great. And it sounds like a natural gas the hedges also include an attempt to reduce basis risk.
Jen Kneale: 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.
Colton Bean: Great. I appreciate the time.
Operator: Thank you. One moment for our next question. Our next question comes from the line of Jeremy Tonet from JPMorgan.
Jeremy Tonet: Hi, good morning.
Jen Kneale: Good morning, Jeremy.
Jeremy Tonet: I just want to kind of walk through, I guess, the results quarter because if you look at the last guide and we overlay kind of the commodities 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 materialize 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.
Jen Kneale: 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 volumes 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, I think, that the business is performing so well that we're really setting up nicely heading into 2023 as well.
Jeremy Tonet: Got it. That's helpful there. And then looking at 2023 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 where CapEx could shake out and how you think about the best way to return capital.
Jen Kneale: I think 2022 provides a little bit of a road map 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 DevCo. No more pros more 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 higher dividend and additional share repurchases. So I think it will be a similar road map 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 2023 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.
Jeremy Tonet: Thatâs very helpful. I will leave it there. Thanks.
Jen Kneale: Thank you.
Operator: Thank you. One moment for our next question. Our next question comes from the line of Brian Reynolds from UBS.
Brian Reynolds: Hi. Good morning, everyone. Maybe just to circle back on . Could you just talk a little bit about the synergies seen so far to capture some of those offloaded volumes. Curious, if you can just talk about how the transaction multiple is being worked out perhaps before all of those volumes fully work its way through the target integrated system in a few years? Thanks.
Pat McDonie: Yes. Red Hills VI came on in September. It's full. Frankly, volumes were greater than the capacity of the system including Red Hills VI. 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 acquiring them 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 â what we call Target North Delaware system, the old Lucid assets in 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.
Brian Reynolds: Great. I appreciate that. My one follow-up entering 2023 just given some operational issues from some peers. There's various projects that are coming online in 2023 but curious, if you could talk about the GCF frac on iLink or if there's any desire to simplify that JV over the next year or two? Thanks.
Scott Pryor: 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 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, those deliveries into Mont Belvieu, the termination of when we would start a Train 10 or restart a GCF asset, we will be certainly taking all those volumes into consideration.
Brian Reynolds: Great. Super helpful. and everyone.
Jen Kneale: Thanks, Brian.
Operator: Thank you. One moment for our next question. Our next question comes from the line of Keith Stanley from Wolfe Research.
Keith Stanley: Hi, good morning. I wanted to start a couple of 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.
Jen Kneale: 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 2023 and actually more in 2024 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 2023 and 2024, but that's what the spending currently looks like right now.
Scott Pryor: And then as it relates Keith to the volume expectations, when we start up Daytona, it will 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.
Keith Stanley : 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 we might hear more on that.
Robert Muraro : Hi. This is Bobby. I'll 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 up would be El Paso coming back online. And then as the PHP and Marathon expansions come online -- the PHP and Whistler come online, sorry, and then Marathon comes online in 2024. I think we'll see the basin 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 capacity we will need through that period of time. As for Targa and long-haul gas pipelines, we want to say no, we'll keep saying that. We'll always say that. If it takes us participating, we're always wanting to participate. If other people get them done and gas gets out of the basin, and bottoms 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 be is the gas costs that our plans keep operating our NGLs go through our system.
Keith Stanley : Thank you.
Operator: Thank you. One moment for our next question. Our next question comes from the line of Theresa Chen from Barclays.
Theresa Chen : Hi, there. I wanted to ask on the comments related to the carbon capture opportunities and your anticipation of receiving 45Q credit. Can you provide some more detail on the nature of the economics with these projects in general and your outlook from here?
Robert Muraro : 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'd 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 make 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 45Q came out. So it's got to -- I won't say it's accelerated our thinking, but it makes us more intention about making sure we get all these done.
Jen Kneale : And then related to timing, Theresa, we said in our script accounts that we thought that we could start getting credits as early as Q4 of 2023.
Theresa Chen : 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 around what percentage of volumes you have currently contracted at this point?
Scott Pryor: Hey, Theresa, 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 US 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 have -- 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.
Theresa Chen: Thank you.
Operator: Thank you. Our next question comes from the line of Sunil Sibal from Seaport Global.
Sunil Sibal: Yes. Hi. Good morning, everybody, and thanks for all the clarity. So when I look at the base G&P 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 from here on should we consider that most of those inflation adjust has kicked in and that are incorporated in the 3Q results, or should we expect any significant movements in that?
Jen Kneale: Sunil, 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 1, then a number of contracts that kick in midyear and then there are 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 will be a net beneficiary of escalators as we move forward through into next year.
Sunil Sibal: Got it. And then could you give us a sense of ethane rejection across your Permian footprint? And what trends do you expect to play out in the near term on that?
Pat McDonie: I'm not sure I fully heard the question.
Jen Kneale: Ethane rejection in the Permian and trends.
Pat McDonie: 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 adding 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 obviously, if that price gets really low, which we've seen recently relative to ethane price, I think you'll see recoveries and ethane being transported to Belvieu.
Sunil Sibal: Okay, got it. Thanks.
Jen Kneale: Thank you.
Operator: Thank you. Our next question comes from the line of Neel Mitra from Bank of America.
Neel Mitra: Hi, good morning. I 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 it limited to 400,000 cubic feet a day because of the limitation on the 30-inch pipe from North Texas to Mont Belvieu?
Scott Pryor: Hey Neel, this is Scott Pryor. First off 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 permit. So it will have the ability to again feed both Grand Prix West as well as Daytona and again take advantage of that line out of North Texas feeding into Mont Belvieu. So, it lines up very well with where our concentration of plant activity is.
Neel Mitra: And if I could just follow-up on that. It seemed like $9.50 is that the limitation from North Texas to Mont Belvieu, or could you get more capacity with pumps?
Scott Pryor: Yes. I would -- we have had a cadence of where we've been putting on pumps both on the West leg as well as the South Lake to complement the volumes that are coming from West as well as in North Texas and up into Oklahoma. I would call it nominally one million barrels per day of capacity on the 30-inch leg going into Mont Belvieu.
Neel Mitra: Okay. Great. And then just the second question, it seems like you've had some commercial success Wildcat II and Winkler to second. Wildcat plant you brought on in the last four years in the legacy Delaware. Could you just comment on the customer mix, or private public and activity you're seeing in that area to cause you to go forward with that project?
Pat McDonie: 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 has 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, that 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.
Neel Mitra: Okay. Got it. Thank you very much
Operator: Thank you. One moment for our next question. Our next question comes from the line of John McKay from Goldman Sachs.
John McKay: Hi. 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 in the midstream side are talking about. And we've seen a couple of the producers starting to slow down. I was just wondering, if you could spend another minute maybe just talking about kind of, what's differentiating your footprint what kind of giving you guys a confidence on the growth outlook and whether or not you have seen a little bit of slowdown from your producer customers?
Pat McDonie: I'll address the last part, first. This is Pat McDonie. We really haven't seen an appreciable slowdown. The people 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 âAcorns 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 is 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 have a time made debt ponds a little bit lumpy. In other words, 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.
John McKay: I appreciate that. Maybe picking up on that one comment from earlier too, I think Theresa's question. Just back to the exports, have you guys commented on what your contracted levels are?
Jen Kneale: John, I'm sorry we could not hear a word of that.
John McKay: I'll try again. Just circling back to Theresa's question on the exports. Have you guys commented, where your current contracted level set?
Jen Kneale: I'm sorry John. We couldn't hear a word of that. Either jump back in and you try from a different line.
John Mackay: Iâll follow-up offline.
Jen Kneale: Okay. Weâll follow-up offline. Perfect. Thank you. Sorry about that.
John Mackay: Thank you. Sorry about that.
Operator: Thank you. One moment for our next question. Our next question comes from the line of Michael Cusimano from Pickering Energy Partners.
Michael Cusimano: 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 are the first three quarters more heavily weighted for that basis than the back fourth quarter. And is that 80% an annual average?
Jen Kneale: The percent 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 ratable at this point in time on the gas side.
Michael Cusimano: Okay. That's helpful. And then on the ethane 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, a 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?
Jen Kneale: 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 are 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.
Michael Cusimano: Okay. Got it. And then, lastly, can you remind us the typical cadence spend for just your standard processing plant, if it's a fourth quarter lead time, how that typically looks and if there's any nuance to the ongoing processing plants that you're working on?
Jen Kneale: 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 the structure 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 II, 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 ratable spending from now until a project comes online.
Michael Cusimano: Okay. Thatâs really helpful. Thatâs all for me. Appreciate the help.
Jen Kneale: Thanks, Michael.
Operator: Thank you. I would now like to turn the conference back over to Sanjay Lad for closing remarks.
Sanjay Lad: 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.
Operator: This concludes today's conference call. Thank you for participating. You may now disconnect.
