Targa Resources Corp. Q3 FY2022 Earnings Call

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 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, VP of Finance and Investor Relations. Please go ahead.

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.

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 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 G&P operations in more detail. Pat?

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 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 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?

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%, 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 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 one 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 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.

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?

Our first question comes from Colton Bean from Tudor Pickering Holt & Co.

Good 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 target NGL egress of Daytona timing were to slip a quarter or two?

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 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 the 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.

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?

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 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 a 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 Tonet from JPMorgan.

Hi, good morning.

Good morning, Jeremy.

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.

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.

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.

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 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 dividends and additional share repurchases. 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 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.

That’s very helpful. I will 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. Could you please discuss the synergies observed so far in capturing some of the offloaded volumes? I'm also curious about how the transaction multiple is being calculated, especially considering that these volumes may not fully integrate into the target system for a few years. Thanks.

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 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.

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.

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, 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.

Great. That was very helpful for everyone.

Thanks, Brian.

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

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.

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.

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.

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.

Hi, this is Bobby. I believe the situation is due to several factors. We have better production than many anticipated, along with more maintenance than planned, and some pipelines remain offline, particularly those going west from El Paso out of the basin. This combination led to significant weakness when multiple pipes went down. A major improvement would be El Paso returning to service. As the PHP and Whistler expansions come online, as well as Marathon in 2024, I expect the basin's condition to improve substantially. We have dedicated considerable time preparing for this, and our team has experience with similar situations. We see a clear path to operate all our assets at the required capacity during this period. Regarding Targa and long-haul gas pipelines, we maintain that we want to be involved and will continue to express that. If others manage to have them operational and get gas out of the basin, we are eager to see that as well. We are always ready to support what's necessary because our goal is to ensure that our plans enable our NGLs to flow through our system effectively.

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 credit. 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. We evaluate these projects similarly to how we assess our traditional economics across the rest of our system. We don’t have specific hurdles, but we do have investment thresholds that the team considers when investing capital in projects. In reviewing our carbon capture projects before the updated 45Q, we found them to be economic. With the new and improved 45Q credit, these projects are becoming even more attractive. While we don’t discuss specific projects or their returns, we see that these projects have improved from being economic by our traditional standards to significantly better now that the new 45Q has been introduced. It hasn't necessarily accelerated our thinking, but it does make us more intentional about ensuring that we complete these projects.

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.

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?

Hey, Theresa, this is Scott. To start, our volumes were 8.5 million barrels per month during the quarter, which is a decline from what we experienced in the second quarter. This drop aligns with the industry's overall performance, which saw a roughly 15% decrease in exports from the US to markets worldwide. The primary reason for this was weaker global markets, particularly involving Asian ethylene producers who faced unattractive economic conditions regarding the co-products and products they manufacture, leading them to reduce their LPG usage. Additionally, there were slowdowns in China due to COVID shutdowns impacting some PDH plant operations. However, we believe that our volumes will improve in the fourth quarter based on our current status and what we have scheduled for that period. While we acknowledge ongoing global market challenges and necessary scheduled maintenance in the fourth quarter, we are optimistic that our volumes will increase.

Thank you.

Thank you. Our next question comes from the line of Sunil Sibal from Seaport Global.

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?

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.

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?

I'm not sure I fully heard the question.

Ethane rejection in the Permian and trends.

The natural gas takeaway situation will have a significant impact. If residue gas cannot be transported, it is likely that more barrels will be produced rather than discarded. Introducing additional MMBTUs into a tight gas market poses challenges. Ultimately, it remains an economic decision, influenced by the ability to move residue gas. Additionally, if the price drops significantly, as we have observed recently in relation to ethane prices, we can expect to see increased recoveries and ethane transported to Belvieu.

Okay, got it. Thanks.

Thank you.

Thank you. Our next question comes from the line of Neel Mitra from Bank of America.

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?

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.

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?

We have been installing pumps on both the West leg and the South Lake to enhance the volumes coming from the West, North Texas, and up into Oklahoma. I would estimate that we have a capacity of around one million barrels per day on the 30-inch leg going into Mont Belvieu.

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?

Sure. It's a combination as you mentioned. We have a significant portion of the major companies committed to both systems. Additionally, in the Delaware Basin, there have been recent acquisitions by major companies that have taken over some of the smaller operators. This has enhanced their portfolio, which is now committed to us. We also have numerous mid- to smaller operators that are very active; some we have partnered with for a long time, and others, as you pointed out, we have successfully worked 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.

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?

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 Acorns 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.

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?

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

I'll try again. Just circling back to Theresa's question on the exports. Have you guys commented, where your current contracted level set?

I'm sorry John. We couldn't hear a word of that. Either jump back in and you try from a different line.

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 are the first three quarters more heavily weighted for that basis than the back fourth quarter. And is that 80% an annual average?

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.

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?

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.

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?

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.

Okay. That’s really helpful. That’s all for me. Appreciate the help.

Thanks, Michael.

Thank you. I would now like to turn the conference 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 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.