Targa Resources Corp. (NYSE:TRGP) Q4 2022 Earnings Call Transcript

Targa Resources Corp. (NYSE:TRGP) Q4 2022 Earnings Call Transcript February 22, 2023

Operator: Good day, and thank you for standing by. And welcome to the Targa Resources Fourth Quarter 2022 Earnings Conference Call. Also be advised that today’s conference is being recorded. I would now like to hand the conference over to the Vice President of Finance and Investor Relations, Sanjay Lad. Please go ahead.

Sanjay Lad: Thanks, Carmen. Good morning, and welcome to the fourth quarter 2022 earnings call for Targa Resources Corp. The fourth quarter earnings release, along with the fourth quarter earnings supplement presentation for Targa that accompany our call are available on our website at targaresources.com in the Investors section. In addition, an updated investor presentation has also been posted to our website. Statements made during this call that might include Targa 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 latest SEC filings.

Our speakers for the call today will be Matt Meloy, Chief Executive Officer; and Jen Kneale, Chief Financial Officer. Additionally, the following senior management members will be available for Q&A. Pat McDonie, President, Gathering and Processing; Scott Pryor, President, Logistics and Transportation; and Bobby Muraro, Chief Commercial Officer. With that, I’ll now turn the call over to Matt.

Matt Meloy: Thanks, Sanjay. And good morning to everyone. 2022 was an excellent year for Targa, and I would like to recognize and thank our employees for their focus, dedication and execution. Some of our highlights from 2022 include record safety performance based on multiyear low total reportable incident rate, record gathering and processing volumes in the Permian, record volumes across our logistics and transportation assets, record adjusted EBITDA of $2.9 billion, a 41% increase over 2021 while also reducing our share count. Major projects came online on time, on budget and have been highly utilized since start-up. Execution and successful integration of our Delaware Basin acquisition and our South Texas acquisition, execution of our corporate simplification with our DevCo repurchase and preferred share redemption, successful sale of our 25% equity interest in Gulf Coast Express Pipeline for approximately 11 times EBITDA, upgrades to investment grade by all of the rating agencies and completion of two successful investment-grade offerings and higher year-over-year return of capital to our shareholders through both an increased common dividend and continued common share repurchases.

We expect our momentum to continue through 2023 and beyond, given the strength of the business fundamentals underpinning our assets. There is a continued need for critical midstream infrastructure like Targa’s to balance and link cost advantaged U.S. production to domestic and global markets. Global events have underscored the critical nature of safe, reliable and affordable fossil fuels to support everyday life domestically and around the world. Cost advantage basins like the Permian, where we are the largest gatherer and processor of natural gas, will continue to be a key supplier of hydrocarbons for decades to come. We are less than two months into the year and already had some notable announcements, including the successful negotiation and closing of our acquisition of the remaining 25% interest in our Grand Prix NGL pipeline, our early January offering of 10- and 30-year senior notes that funded the Grand Prix acquisition and reduced floating rate borrowings on our revolver.

And within this morning’s release, our operational and financial estimates for 2023, which are expected to be records across many fronts, including an estimated 24% increase in year-over-year adjusted EBITDA. Our transfer and construction of a plant from our South Texas acquisition to the Delaware Basin, which we are calling the Roadrunner II plant, where activity around Southern New Mexico is currently exceeding our expectations. And an expected 43% year-over-year increase to our 2023 annualized common dividend per share versus last year. For 2023, we estimate that our adjusted EBITDA will be between $3.5 billion and $3.7 billion. The significant year-over-year increase in adjusted EBITDA is driven by higher expected gathering and processing volumes, higher expected NGL transportation, fractionation and export volumes, higher expected marketing optimization and LPG export opportunities, higher fees from contract escalators, a full year contribution from our Delaware Basin and South Texas acquisitions, contribution from our acquisition of the remaining 25% interest in Grand Prix and higher hedge prices.

Related to capital allocation, maintaining a strong investment-grade balance sheet across cycles continues to be a priority at Targa. We also have attractive opportunities to continue to invest organically, which we believe will support the continued creation of significant shareholder value over time. We currently estimate between $1.8 billion and $1.9 billion of growth capital in 2023 as we build infrastructure that we expect to be highly utilized across our footprint. Our major projects in progress are core to our business, five new Permian gas processing plants, Train 9 fractionator and our Daytona NGL pipeline. Along with our partners, we are also in the process of restarting the 135,000 barrel per day Gulf Coast fractionator in Mont Belvieu, which we expect to be operational in the first quarter of 2024.

Beyond those projects already announced, and in progress, we are evaluating when we will need additional gas processing capacity in the Permian, and we are ordering long lead time items for our next Midland plant. We believe our organic growth opportunities create value for Targa and our investors over time as we have demonstrated strong returns over the last five years. As you can see from Slide 4 in our earnings supplement presentation, we generated an attractive 26% return on invested capital since 2017, despite a volatile commodity price backdrop over the last several years. For our recent major capital projects, we have invested at a low single-digit multiple of EBITDA as the immediate high utilization of assets like new gas processing plants have resulted in very attractive returns despite higher build costs from inflation.

A strong balance sheet and continued investment in high-return projects positions us to continue to prudently return an increasing amount of capital to our shareholders across cycles. We announced an expectation of a 43% year-over-year increase to our annualized 2023 common dividend per share this morning. The increased dividend will be recommended to our Board in April for the first quarter of 2023 with payment to shareholders in May. Our expected 2023 dividend increase reflects a lot of different factors, including our near- and long-term business fundamentals and balance sheet strength across scenarios, flexibility associated with our increasing size, scale and fee-based margin and Targa’s positioning relative to our midstream C-Corp peers , the S&P 500 and cyclical industries within the S&P 500.

We also expect to be in a position to continue to execute opportunistically under our common share repurchase program, which will allow us to further increase our return of capital to shareholders and reduce our share count over time. We bought back $225 million worth of common shares in 2022 and had about $144 million remaining under the $500 million share repurchase program we put in place in October 2020. Our current expectation is we will request Board approval to authorize a new $1 billion share repurchase program once we exhaust our existing program. We believe that we will offer a unique value proposition for our shareholders and potential shareholders, growing EBITDA, growing dividend and reducing share count. We expect to continue to set expectations for our annual common dividend each February when we announce our financial and operational guidance and expect to continue to increase our return of capital to shareholders over time.

In addition, to our standard annual disclosures around our financial expectations, we also included in our investor presentation this morning, describing Targa across upside and downside commodity price scenarios. We have spent the last many years focused on increasing our cash flow stability and reducing our volatility to downward moving commodity prices. As you can see from Slide 12 in our earnings presentation relative to our full year 2023 financial guidance, a 30% move higher in commodity prices from our guidance levels would increase adjusted EBITDA by around $100 million, while a 30% decrease would reduce adjusted EBITDA by around $60 million. This asymmetric risk, where we have significantly more upside than downside across commodity prices continues to be an area of focus at Targa where our commercial teams are working really well with our producers and other customers to maintain alignment to be in a position to continue to invest across cycles.

As we look forward, we believe that Targa is in excellent position to continue to provide best-in-class service to our customers and create additional value for our shareholders. I will now turn the call over to Jen to discuss our fourth quarter and full year 2022 results in more detail as well as our expectations for 2023.

Jen Kneale: Thanks, Matt. Good morning, everyone. Targa’s reported quarterly adjusted EBITDA for the fourth quarter was $840 million, increasing 9% sequentially as we benefited from the first full quarter of our Delaware Basin acquisition, optimization opportunities and recent processing additions across our Permian systems despite lower commodity prices and operational impacts from Winter Storm Elliott. Full year 2022 adjusted EBITDA was $2.9 billion, 41% increase over 2021, driven by record volumes in gathering and processing, NGL transportation and fractionation. Our consolidated leverage ratio at the end of the year was 3.7x well within our long-term leverage ratio target range. We spent approximately $552 million on growth capital projects in the fourth quarter and our full year 2022 growth capital spend was $1.177 billion, about $30 million of growth capital shifted from 2022 into 2023.

Maintenance capital spend for 2022 was about $168 million. We repurchased approximately $28 million of common shares in the fourth quarter. And as Matt mentioned, had approximately $144 million remaining under our $500 million share repurchase program at year-end. In early January, we announced and shortly thereafter closed our acquisition of the remaining 25% interest in our Grand Prix NGL pipeline for approximately $1.05 billion. The acquisition price represented an 8.75x multiple of Grand Prix’s estimated 2023 adjusted EBITDA, which we believe was an attractive purchase price. With 100% ownership of Grand Prix, including our Daytona pipeline expansion, we benefit from having significantly more operational flexibility and also near and longer term capital synergies.

We funded the Grand Prix acquisition through a successful $1.75 billion offering of 10 and 30 year senior notes and used the incremental proceeds to reduce borrowings on our revolver. We currently have about $2.5 billion of available liquidity, which provides us with a lot of flexibility looking forward. Turning to our expectations for 2023, as Matt described in his remarks, we really are very excited about the continued momentum at Targa. We estimate full year 2023 adjusted EBITDA to be between $3.5 billion and $3.7 billion, a 24% increase over 2022 based on the midpoint of our range, assuming commodity prices of $2.25 per MMBtu for Waha natural gas, $0.70 per gallon for our weighted average NGL barrel and $75 per WTI crude oil barrel. We are well hedged across 2023 and beyond and are benefiting from significant additional fee-based margin year-over-year.

We expect significant margin benefit in the first quarter from increased LPG exports, natural gas and natural gas and NGL marketing optimization opportunities. Please see the additional disclosures that we added to our investor presentation this morning on sensitivities to commodity price changes and our hedges. We currently estimate between $1.8 billion and $1.9 billion of growth capital spending based on announced projects and other identified spending and $175 million of net maintenance capital spending. Operationally, high activity levels continue across our dedicated acreage in the Permian. Our reported full year 2023 average Permian Basin natural gas inlet volumes are projected to increase about 10% over average fourth quarter 2022 Permian inlet volumes.

There is no change to the estimated in-service dates of our plants under construction with the Legacy II and Midway plants expected in service in the second quarter of 2023. Greenwood in service late in the fourth quarter of 2023 and Wildcat II in service in the first quarter of 2024. As Matt mentioned, we are also moving a plant acquired in our South Texas transaction to the Permian Delaware which we are calling Roadrunner II and expect in service in the second quarter of 2024. The significant increase in Permian Basin volumes is expected to result in record NGL transportation and fractionation volumes in 2023. There is no change to the expected in-service dates of our major downstream projects with Train 9 expected to be complete in the second quarter of 2024 and the Daytona NGL pipeline complete by the end of 2024.

GCF will provide some much needed help on the fractionation side, and we expect it fully restarted in the first quarter of 2024. We will also benefit from the mid-2023 completion of our project at our Galena Park LPG export facility, which will increase our propane loading capabilities by about 1 million barrels per month. We are well contracted across our export facility and are estimating that 2023 will be a record year for LPG export volumes for Targa as well. We expect to pay an annualized common dividend in 2023 of $2 per share and have the flexibility to continue to use our common share repurchase program opportunistically to return incremental capital to shareholders through the year. Our balance sheet is strong with leverage near the midpoint of our long-term leverage ratio target range of 3x to 4x, and we expect to end 2023 around the midpoint of our range, providing continued flexibility for Targa going forward.

Lastly, I would like to echo Matt and extend a thank you to our employees, their continued focus on safety while executing on our strategic priorities and continuing to provide best-in-class services to our customers. And 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 lineup if you have additional questions. Carmen, would you please open the lines for Q&A?

Q&A Session

Operator: Thank you. And we have our first question from the line of Jeremy Tonet with JPMorgan. Please go ahead.

Jeremy Tonet: Hi, good morning.

Matt Meloy: Hey, Good morning, Jeremy.

Jen Kneale: Good morning.

Jeremy Tonet: I wanted to touch on the 2023 guide, and I want to touch on three components to it, if I could. Just wondering as far as Permian volume growth, I’m just wondering, the growth seems very strong here. Do you see yourselves growing faster than the base on your acreage? Or do you see yourself taking market share just curious on the drivers of the strong Permian growth there. And then also, I guess, the drivers €“ what are the drivers behind marketing optimization stepping up in LPG exports stepping up? Just color on those points would be super helpful.

Matt Meloy: Yes, sure, Jeremy. On the Permian growth, yes, we are seeing significant activity across our acreage, both in the Delaware and the Midland, so part of that relates to the recent acquisition that we made. There is a lot of activity. And frankly, it’s exceeding our expectations for the opportunities there. I don’t know, Pat, do you want to give some additional color on what we’re seeing in Permian?

Pat McDonie: Sure. And if you think about this year versus last year, you start January and February with basically 50 more rigs than what you had last year. They levelize for the remainder of the year, but obviously, off to a better start than what we saw last year. Then when you look historically of how Targa performed in the Midland Basin, we always have outperformed the average growth across the Midland Basin. We performed well in the Delaware Basin, but Lucid on the other hand, significantly outperformed the average growth in the Delaware Basin. So with that asset in our Delaware side of our overall Permian portfolio, we have the best-performing assets on the Midland side, the best-performing assets on the Delaware side. That coupled with the rigs currently running on that acreage. Our line of sight with a great producer group and what they’re doing, and we’re very in tune with them. We feel very, very good about our volume forecast.

Scott Pryor: And then Jeremy, as it relates €“ this is Scott, as it relates to the LPG export business and the growth that we’re seeing for 2023. Just recognize third quarter versus fourth quarter. Our fourth quarter volumes were up. We expect that our first quarter volumes here in 2023 will be up there. And then obviously, with the increase in production that we’re seeing, on our integrated platform, speaking to what Pat was talking about feeding through our downstream assets, we see opportunities there for continued growth. And that is certainly complemented by the growth that we’re seeing across the global marketplaces. Benefiting on that side is things like the reopening of the Chinese marketplace. Increased demand for PDH demand in Asia as a result of that.

We’ve also seen improvements on the shipping side because we’re seeing new deliveries of VLGCs which is providing more liquidity on the water and certainly some improvements in efficiencies out of the Panama Canal. So I think the combination of all those, which will certainly also benefit with the small expansion that Jen spoke to in her opening comments, that will be online mid-year. That 1 million barrels per month of additional capacity will just complement what we’re doing. And as Jen also mentioned, we continue to be highly contracted while also feeling comfortable about the available space that we would have to participate in a spot market when the market presents itself. So that lends flexibility to our customers, reliability to our customers while also providing economic benefit to Targa when the pricing firms up at times.

Matt Meloy: Yes. And just to add to that, Scott, and Jeremy, I know you asked about our optimization on our marketing, I’d say we had really good opportunities in the fourth quarter in both NGL markets and natural gas markets as we move a lot of volumes of both products. And when there’s increased volatility, which we saw in the fourth quarter, we were able to optimize and make some additional margin there. And we’re off to a strong start in the first quarter as well, which is why we kind of pointed to that in our 2023 guide. So we’re already kind of factoring in some of that that has already occurred this year. So we do expect a strong first quarter because of some of that optimization as well.

Jeremy Tonet: Got it. Great to hear, strong data points across all three components there. And just one last question, if I could. I want to touch on capital allocation a little bit more, and you gave some thoughts in the prepared remarks and in the PR, but I just wanted to touch on, I guess, how you think about that in the future? I mean, we had a very nice 43% step-up in the dividend here. It’s going to be an annual determination going forward. But €“ how do you see €“ can you give any more color on what future years could look like to bookend us to make sure we don’t get off the rails. And as far as capital spend is concerned, is this kind of how €“ kind of closer to the peak? Or do you expect this level to persist?

Matt Meloy: Sure. Yes, Jeremy, on capital allocation, our priority within how we want to spend both organically and return capital to shareholders. We want to start with a strong balance sheet and make sure we have flexibility to continue to invest and to continue to return capital to shareholders over time. The good thing about our forecast and what we’re showing this year is we think we can do all of that. We think we can grow our EBITDA, invest in our business while significantly increasing the dividend, which we did €“ or which we anticipate to do for 2023. I think we have the ability for future significant dividend increases as we go forward. Just as you look at our EBITDA growth, strong balance sheet, I think we’ll have some ability to continue to grow the dividend while continuing to buy back shares.

We were pretty active in 2022, buying back shares. I see us being opportunistic in how we buy back those shares, but we have the significant ability to continue to repurchase shares. So that is where we see us position, growing our EBITDA, growing our dividend and reducing our share count over time.

Jeremy Tonet: Wonderful. Thank you so much.

Matt Meloy: Okay. Thanks, Jeremy.

Operator: Thank you. And it comes from the line of Brian Reynolds with UBS. Please proceed.

Brian Reynolds: Hi, good morning, everyone. Maybe just to follow-up on some of the guidance assumptions. You talked about the 10% Permian exit-to-exit growth, which implies just really strong Permian growth once again. You recently had some plants come online full during 4Q, and it seems like plants can’t come online fast enough with over half of capacity coming online next year. So curious of how much of those offloaded volumes coming back on the Targa system post the Lucid acquisition is baked into that volume forecast? Or should we effectively assume those volumes coming back onto the system as upside to your Permian growth forecast? Thanks.

Pat McDonie: I would say that we do have some offloads in the Delaware Basin and minimal on the Midland side because we just brought a plan up, right? And we’ve got another plant coming up fairly quickly in the next, call it, six to eight weeks on the Midland side. So we feel like we’re in pretty good shape in Midland. And there isn’t anything currently being offloaded that will come back on to the system. On the Delaware side, because Lucid was behind in processing capacity, we had some things to do there. We brought up the Red Hills VI plant in September. Frankly, it was immediately full. We had existing connections between the Targa Delaware system and the Lucid system, which we were immediately able to offload 150 million a day into our Far West plant complex is the Peregrine and Falcon plants and we had available capacity.

We also had contracted some third-party offload capacity, which we have retained because, frankly, the performance of those assets is better than what we had in our acquisition case. And I think you can see by what we’ve announced, we’ve got the Wildcat II plant coming on. Midway will be that €“ Midway that will be that midway point, basically adding capacity in May. Wildcat II at the end of the year, the very beginning of next year because of the anticipated growth and the Roadrunner announcement right behind that coming on because, frankly, we’re going to need it. But we’ve done some things in the meantime. We’ve increased our ability to move the old Lucid system, what we call Targa North Delaware gas into our Far West plants, which, again, we have available capacity.

So over the next, let’s call it, 9 months to 12 months, one will fill up the Midway capacity. We had a little bit of remaining capacity at Wildcat. We have a sweet plant at Loving that’s kind of our swing plant that will fill up. And then we utilize the offload in the Peregrine and Falcon capacity to get us to the Wildcat II plant. And don’t forget, we have the ability to run our plants over nameplate, which can give us another 100 million to 150 million a day of incremental capacity.

Brian Reynolds: Great. Thanks. Sounds like there’s a significant amount of roadway of growth in the Delaware over the year. As my follow-up, the last 24 months, we’ve just seen Targa integrate and simplify itself in a series of transactions to become the S&P 500 company it is today. Moving forward, as you talked about, there seems to be a healthy amount of organic growth opportunities within Targa. And thus, given the amount of organic growth backlog, should we view the recent Grand Prix M&A as kind of the last piece of simplification of Targa at this time? Or are there other missing pieces to the portfolio that could use some of that excess free cash? Thanks.

Jen Kneale: This is Jen. I don’t think that there are any missing pieces to the portfolio. I think we are very pleased with the asset footprint that we have and see significant opportunities for continued organic investment going forward that will help underpin that increasing year-over-year EBITDA growth that we expect. The Blackstone acquisition, you’re exactly right. That, in our view, was an acquisition, but a simplification as well. And I think operationally and in terms of how we invest capital around our NGL transportation assets going forward, it just gives us enhanced flexibility. So we do see that as sort of the final piece of our simplification story. Going back to beginning with the DevCo and then the TRC preferred repurchase.

Brian Reynolds: Great. I’ll leave it there. Thanks for the color and enjoy the rest of your day. Thanks.

Jen Kneale: Thank you.

Matt Meloy: Okay. Thank you.

Operator: Thank you. And it comes from the line of Spiro Dounis with Citi. Please proceed.

Spiro Dounis: Thanks, operator. Good morning, team. I wanted to go back to the commodity sensitivity that and that asymmetry that Matt referenced earlier. I guess it’s a bit different than how you guys were traded in the past. And I guess I’m just curious, is that an indication that that fee floors could trigger before a 30% down move in commodity prices. I know the calculation is probably a bit complex, but just curious how you’re thinking about the fee floors and maybe what’s embedded in that low end of the guidance beyond the commodity move down?

Jen Kneale: Spiro, this is Jen. We’re really proud of the efforts of our commercial teams over the last many years to put in fee floors really across our gathering and processing businesses. And part of what we wanted to provide today was additional information that indicates that the Targa of today looks very different than the Targa of several years ago. And a big reason for that is the fee floors that we have in place. So we tried to publish was that if you had a significant move downward in commodity prices, it would be, call it a 30% down move would be about a $60 million impact to our 2023 adjusted EBITDA. And I think that is again reflective of not only the fee floors, but we also just have a lot more fee-based margin now both on the logistics and transportation side, which is essentially all fee-based margin and then also on the gathering and processing side, where the Lucid acquisition was the latest element of fee-based margin that we brought into the portfolio.

So I really think it’s a combination of a number of factors that we think demonstrates that Targa’s downside exposure is significantly reduced today than what it was previously. And that’s all enhanced by our hedging program that really hasn’t changed over the last several years. But I do think that it’s realistic to assume that in a 30% leg down in commodity prices across the Board versus what we had in our guidance, the fee floors would all be in play at that point.

Spiro Dounis: Okay. Got it. That’s helpful. Thanks for that, Jen. And then maybe just to go back to the volume growth. It sounds like it is exceeding expectations and a lot of discussions so far has been around the processing plants. And Jen, I know you mentioned that all the in-service dates for expansions, including Daytona, are all still in place. But I guess on my math and just based on some of this discussion, it would seem like Grand Prix is going to get pretty tight potentially before Daytona could come online. So I’m just curious, is there an ability to bring that on sooner or in phases? Or do you have any sort of bridging solutions if that gets tighter than expected?

Scott Pryor: Spiro, this is Scott. First off, I would say that when we look at Grand Prix, we’ve been €“ obviously, the success of that is evident. And the continued growth that we’ll see in the Permian will feed into that. Just recognize that as we enter into 2023, we’ve got some additional pump stations that will commission throughout 2023, probably more heavily in the first half of this year versus the back half of the year. And during that time frame, we would push our overall capacity up to what we call our nameplate of roughly 550,000 barrels a day just on the West leg alone. We feel comfortable that we can likely operate above that, call it, in the 600,000 barrel a day range. And then we will certainly be expediting as quickly as we can the installation of the Daytona pipeline.

Fourth quarter of 2024 is kind of where we’re at with that. We’re calling at the end of 2024, but we’ll be working hard to make sure we get that online as quickly as possible. In the interim, if we do have some situations where we need to offload capacity, we’ve got a number of plants that are connected to multiple pipelines, and they’re not solely dependent upon just the Grand Prix pipeline. So we feel that we’ve got a lot of flexibility to manage through it. We certainly want to make sure that it’s preferred that the volumes are moving on our pipelines. But we’ve got some opportunities to manage through that, if necessary, if the volume growth exceeds our expectations.

Spiro Dounis: Great. Appreciate all the color today, guys. Thank you.

Scott Pryor: Okay, thank you.

Operator: Thank you. And it comes from the line of Theresa Chen with Barclays. Please go ahead.

Theresa Chen: Good morning. I’d love to get your take on the frac outlook, given the tightness that we’re seeing evidence in anecdotes of tightness in the Gulf Coast, maybe most recently from the restart announcement at GCF, would you mind giving us an update on your outlook on utilization for the part of the value chain and general demand outlook for the purity product maybe touching on some that LPG export commentary? What are you hearing from your petchem customers? What are your general expectations for demand for ethane and LPGs?

Scott Pryor: Again, this is Scott. So when we look at the fractionation complex that we have, certainly bringing on GCF that the partnership has agreed to restart. That will start. We expect to commission that in the first quarter of 2024, and that will be needing capacity. I will say that when you look at our volumes that we had from third quarter to fourth quarter of 2022, those probably don’t illustrate exactly the volume growth that we’re seeing over time across our various assets and alluding to the comments that Pat made as it relates to our growth on the G&P side of our business. We did have some planned and unplanned outage at our facility during the fourth quarter, which really basically is behind us now. So we feel as though that we should be at our €“ basically at our full complement of fractionation capacity going forward.

And some of that, when you look at the impacts of that, we’re also impacted by Winter Storm Elliott. We obviously have substantial amount of storage that allows us to manage the influx of products on the inbound side, whether it’s Y-grade, spec products as well as on the outbound side. So we feel very comfortable with that. But certainly, the additive of Train 9 coming on in the second quarter of next year will be an important piece of the pie for us from a fractionation perspective. As it relates to the distribution of products on the spec side, certainly, products of inflow of product coming into us. The LPG export facility that we have at Galena Park is a very important integral piece of our platform that we have today for propane as well as butanes.

And again, what we mentioned earlier with the small expansion we have that provides us additional capacity there. And so we feel very comfortable with our expectations on that side. As it relates to ethane, certainly, the market continues to pull on the ethane molecule. We’ve had a number of petchem expansions that have been announced recently. New expansions have come online over the course of the last two years. And our team has done an excellent job as we’ve added fractionation capacity as we have future expansions that are coming online, the team has done an excellent job of increasing our connectivity to the downstream petrochemical market to make sure that we can clear that ethane molecule. So we view that that is a continuation of that.

And I think the petchem industry is starting to really get more on solid footing as it relates to improvements in the global economy that going forward look good for us.

Theresa Chen: Thank you. And Jen, I wanted to go back to your comments about the breakdown between fee-based versus commodity-based margin. Now that you are 85% fee-based, as you bring online incremental processing capacity embedded with contract escalators over time fee floors, et cetera, how do you think this breakdown evolves? And with the asymmetric risk that you currently see within that 60% band, do you see that becoming more favorably skewed going forward as you layer in more for fee floors and general fee-based margin?

Jen Kneale: I think that we have demonstrated a commitment to our producers to continue to invest capital and infrastructure to support their drilling activities. But in order to do that, we need to have protections in place that we’ll get at least a minimum rate of return on that invested capital. And so I think that we have seen good support in our areas where we are spending capital to put in fee floors and we are trying to bring that to other basins as well as contracts come up for expiration or there’s a catalyst for a renegotiation. And I do think it creates excellent alignment for us to continue to invest and benefit from higher commodity prices, but have a little bit of production in a lower commodity price environment.

I think it’s difficult to see us going from 85% fee-based margin to 100% fee-based margin just by the nature of our assets. I think we’re also very comfortable with the commodity price exposure that we have, particularly if it can be with a fee floor structure in place. So I think that’s the trend that will continue for us. And our commercial teams have really done a great job of putting those fee floors in place when they’ve had the opportunity to do so. And so I believe that, that will continue to be a big point of focus for us, but it’s difficult to predict what that means in terms of where fee-based margin goes in the future. But I would expect that we will continue to have more margin protected with the fee floor structure.

Theresa Chen: Thank you.

Operator: Thank you. And it comes from the line of Colton Bean with Tudor, Pickering, Holt & Co. Please proceed.

Colton Bean: Good morning. So the transport and frac unit margins were up materially relative to Q3. Any drivers on that apart from lower OpEx? And was there a mix shift in basin origin or any contracts that moved around and then between the two transport and frac any weighting in terms of the margin uplift?

Matt Meloy: Yes, sure. Hey, Colton. We really benefited from a couple of things there. We had, as I mentioned before, some optimization just related to our marketing activities in both NGL marketing and gas marketing. What Scott also mentioned is our fracs that we had some planned and unplanned maintenance, we were bringing in more fractionation volumes, and we were able to fractionate. So here in the first quarter, those are behind us, and we’ll be operating closer to nameplate, so we have the opportunity to either build inventory or to do some offload. So we were able to execute some offload at cheaper rates than our overall T&F. So it kind of creates the margin spread for us even though our volumes did move up as much. So I’d say we have more volumes coming in than kind of what was reported because that’s what we actually fracked, but we were able to do some third-party offloads that work is really behind us.

So we have more capacity now in Q1. So that is, for us, creating a little bit more flexibility in terms of the overall frac market. And with other fracs coming on in 2023, we see some looseness in 2023 in the frac market. So we’ll be able to, I think, be in good position ahead of GCS start-up and Train 9 coming on. But it was really a combination of all those things.

Colton Bean: Okay. And so it sounds like it was more concentrated on the frac side and relatively stable for transport?

Matt Meloy: Yes. I think that’s about right.

Colton Bean: Great. And then on OpEx. So Q4 was relatively flat for G&P and actually down in logistics. I think previously, you were expecting continued increases as you had a full quarter of Lucid and then higher overall activity. So just €“ was Q4 more of a structural shift in your outlook? Or should we still expect that step-up in expense levels heading into 2023?

Jen Kneale: Colton, this is Jen. What tends to happen is through the year, we overestimate what our ad val costs may end up being just because we generally tend to forecast conservatively. And so as those costs come in throughout the year, it means that often fourth quarter OpEx for us steps down a little bit versus prior quarters on that front. So that was a benefit for us in the fourth quarter. And then our teams have also done just an excellent job of managing our operating expenses as well. Within the fourth quarter, we did have OpEx associated with Winter Storm Elliott, which our team did a great job of managing through. We’ll actually have a little bit of OpEx that comes into the first quarter related to Winter Storm Elliott, but it’s also just a really well management, particularly on the G&P side, where we did have the step up or expected step-up from the Lucid acquisition and then managed it very, very well.

On the downstream side, we had the benefit also of lower ad valorem costs in the fourth quarter. And we also had repairs and maintenance in the third quarter that Scott mentioned. And so there was a step down there just because we did not have those repairs and maintenance in the fourth quarter. Those were one-time.

Colton Bean: Great. Appreciate the time.

Jen Kneale: Thank you.

Matt Meloy: Okay. Thanks, Colton.

Operator: Thank you. One moment for our next question, please. And it comes from the line of Keith Stanley with Wolfe Research. Please go ahead.

Keith Stanley: Hi. Good morning. Thank you. Just wanted to start on commodities and hedges. So if I compare the hedge prices for 2023 to the forward curve where it sits, are your hedges now in the money, would you say, for this year? And so additive to EBITDA or are they below market still? Asking across commodities, just to try to give a better picture of where an unhedged outlook might be for 2023 versus the $3.5 billion to $3.7 billion guidance?

Jen Kneale: On the hedge disclosures that we gave this morning on the natural gas side, that’s aggregated swaps across everywhere that we hedge. So I’d say that the majority of those hedges are Waha swaps where actually would say that Waha prices for balanced 2023 are now lower than where we have hedged. So it’s a little bit of a mixed bag depending on each basis point that we hedge to and the swaps that we have in place there. On the NGL side, I think where prices are right now is really since the beginning of the year, we’ve seen NGL prices that are a little bit higher than where we have hedges in place. We’ll just have to see how that plays out for calendar 2023, and we’ll be continuing to layer in hedges as we move through time and then our exposure to WTI crude prices just isn’t that significant, but prices are a little bit lower, I think, today than where we’ve got our hedge prices sitting.

Keith Stanley: Okay. So overall, big picture, you’re a little above market on gas, a little below on NGLs and crude, but net-net, it doesn’t sound like the hedges materially change what the EBITDA outlook is for the year?

Jen Kneale: No, I think that’s fair. We had, call it, north of $400 million of hedged losses in 2022, and we’ve said that we’re hedged at higher prices this year. So articulated that that was a tailwind for 2023 relative to 2022. And then when we think about where hedges are relative to where prices sit today, maybe a little bit of a tailwind, but we’ll have to see how it plays out through the year.

Keith Stanley: Got it. Okay. Thank you. Second question was just on the CapEx guidance, are you baking in any spend for unannounced plants or other likely future spending? And related to that, just how are you thinking about the potential need to start work on a frac 10 before the end of this year? Or is that now pushed out into 2024 with the GCS?

Matt Meloy: Yes, sure. So for €“ we have the five plants that we have announced. And also said in the script, we are ordering long lead time items for another plant in the Permian Midland. So we factored in some of that CapEx into this overall guidance. So it really depends on when we greenlight that and say, okay, we are going forward with it. So there could be some additional shift of capital if we greenlight that plant sooner rather than later. And I’d say right now, we are evaluating even though we’re adding Wildcat II and Roadrunner II, we are evaluating potentially another plant out in the Delaware. So we’re going to see kind of how the first part of this year plays out and if we need to go forward with another plant sooner rather than later.

Right now, that’s not factored in. We’re evaluating. We have a lot of plants coming on between the Midway Wildcat II, Roadrunner, and we have some offload capability. So we’re trying to be capital efficient there, but we kind of have our eye on when we’re going to need another plant in the Delaware. As far as frac Train 10, again, I think let’s see how volumes kind of play out this year and what producers are saying for next year. We have Train 9 coming on. We have GCF coming on. But we are talking about when we’re going to need Train 10 when you have kind of 10-ish percent growth on the footprint that we have, that significant amount of NGLs moving through Grand Prix moving into our frac. So I’d say we’re having discussions on when we’re going to need to add Train 10, and we’re trying to kind of evaluate that as the year plays out.

Keith Stanley: Thank you.

Matt Meloy: Okay. Thank you.

Operator: Thank you. One moment for our next question, please. And it comes from the line of Neel Mitra with Bank of America. Please proceed.

Neel Mitra: Hi. Good morning. I was wondering if you could speak to the capital associated with moving Roadrunner to the Delaware. How that would compare to a new build? And then where would you be moving that plant into the Delaware? And where are you seeing that pocket of growth that would require that plant to be moved there?

Matt Meloy: Yes, sure. What’s great about where we’re moving that is it’s connected to our existing footprint, so the Roadrunner II will be right next to the Roadrunner I plant, which was part of the Lucid acquisition. There’s the Red Hills complex and the Roadrunner, which will now be a complex when we add that there. The overall capital fed is about $120-or-so million for that move. So it is capital efficient relative to just doing a new build. The new builds are, say, closer to $175 million, give or take. Those are €“ the new builds are about $275 million. The Roadrunner move is about, call it, $230-or-so million. So you get a little more capacity on the new build, but still on a per unit basis, a little bit better for the move and timing, being able to move it does help our timing. As Pat mentioned, we’re getting tighter on capacity out there. So moving it is quicker than just putting a new build out there.

Neel Mitra: Okay. So just to clarify, this would be for the Lucid acreage and wouldn’t necessarily connect to Grand Prix. Is that fair?

Matt Meloy: What’s interesting is what’s the Lucid acreage were started now it’s all Targa and it’s really getting mixed. When you talk to producers, is it €“ a Targa system, it’s all becoming really quickly all one system out there. And Sorry, Bobby, do you want to add some color on that?

Bobby Muraro: Yes, this is Bobby. I was just going to say also when you think about the scale of the system in the Midland Basin and the fungibility across areal extent of it. You don’t exactly drop a plant right on top of acreage that you see coming because we can move volumes across the entire system. So as we start to build out the Delaware in the same manner, such that we’re putting plants, generally speaking, where we see growth. All the growth doesn’t have to happen right at the top of the year because of the fungibility of that system. And the integration of the loose assets that we bought into our existing asset footprint with the big AMI we did with Chevron several years ago, it creates fungibility such that, that’s a convenient place and a fast place to put Roadrunner, but it also is gas can flow from lots of different spots to that plant.

Matt Meloy: We’re also working to connect Roadrunner and integrate that system into Grand Prix, so we’re building that line now.

Neel Mitra: Got it. And then if I could just follow up on Grand Prix. It seems like for the second half of 2022 volumes were relatively flattish. And I know early 3Q, you had some ethane rejection and that’s set to recovery, maintenance and weather, should we see a step-up back in kind of 1Q? Or are there any other kind of lingering issues on Grand Prix in the volumes for you, you start stepping back up to kind of be consistent with the processing growth?

Matt Meloy: Yes. We expect volumes to start moving higher here as we get into the year. What you see there is Grand Prix is mix between Permian and our North leg, which goes up into Oklahoma. We’ve seen continued growth on our West leg. We have seen volumes move South a little bit kind of as we’ve not as much strength there as you’ve seen in the Permian. So it’s looked relatively flat. But we are already seeing it. Frankly, the start of this year we’re seeing volumes move higher, and that’s what we would expect in Grand Prix as we move through the year, pretty strong growth there.

Bobby Muraro: And I would also just add, Matt, that we’ve got €“ the second half of this year, we’ve got some third-party contract contribution that will be coming in from the North leg more the back half of the year. So you’ll see those volumes starting to ramp up for deliveries into Belvieu as well.

Jen Kneale: And just so we touch on every quarter of growth for Grand Prix. In the second quarter, we’ll have Legacy II coming online and then the additional capacity available at Midway. So those will be nice catalysts in the second quarter.

Matt Meloy: Yes.

Neel Mitra: Got it. Thank you for all the color.

Operator: Thank you. And comes from the line of John Mackay with Goldman Sachs. Please go ahead.

John Mackay: Hey. Thanks for the time. Wanted to just sit on Permian growth for another half second and clarify one comment from before. Were you saying that €“ the growth outlook right now is 10% off of fourth quarter 2022 assumes no incremental rate adds off of what we’ve seen so far through February? That’s the first part. And then second, I’d love to just hear how you’re thinking about the other basins, relatively less gas-driven exposure, of course, but we’re seeing slowdowns elsewhere. So curious what your view on maybe the Barnett and others look like? Thanks.

Matt Meloy: Yes. I’ll hit the first one, and then Pat can comment on the second. Yes, we were not specific on the rig adds I’d say we do a bottoms-up build with our producers in both Midland and Delaware, and there’s a combination of some folks adding and doing more and some doing less or shifting, so it’s an aggregate of all of those. We don’t €“ we haven’t given one number instead it assumes rig adds or takeaways. It’s a bottoms-up build, but we also kind of do a top down and say how they performed relative to history. And then what do we really expect to do. So it’s kind of the usual way we do a forecast on that. And then, Pat, do you want to hit on other basis?

Pat McDonie: Sure. We’ll start in Oklahoma. We’ve seen, frankly good activity in both our South Oklahoma and our Western Oklahoma areas. Good activities relative to, let’s call it the last three, four years prior to that, obviously, there was a lot of activity. But enough so that we’re able to offset decline. Frankly, in Southern Oklahoma, we show where we were basically flat and frankly that includes a pretty significant chunk of volume rolled off under a contract, and we were able to fill that back in behind. So we are seeing some activity there. North Texas, we have €“ we’ve seen volume growth on our system, and we continue to see drilling activity. Certainly, it and frankly Southern Oklahoma are more sensitive to gas prices.

So we have expectations at the beginning of the year here that we’ll get to incremental volumes. There are planned drilling on our system throughout the year. We’ll ultimately see how those pan out dependent upon commodity prices and the decisions of those producers. Our South Texas activity has been very good. The addition of the Southcross assets and the sour gas capabilities there have added a level of drilling activity and some of our contracts that originally underpinned the assets, those producers are active. So we’ve seen benefits in volumes from both of those kind of types of producers. So we feel good about volume growth there, but it’s not significant in the overall scheme of things. same thing, a good steady pace of drilling. So good replacement of crude oil and natural gas, are we going to say how we’re going to significantly grow in that basin.

Now are we going to hold our own and see some slight growth probably?

John Mackay: All right. That’s great. Thank you for all that. Maybe just one last one for me on CapEx. Just curious if you could talk a little bit about any inflation pressure you’re still seeing flowing through, whether that’s on the plants or on kind of just gathering compression side, just anything kind of directionally there? And how we can kind of think about that going forward? Thanks.

Matt Meloy: Yes. We are seeing some higher costs, whether it’s compression pipelines or just the larger facilities we’re putting in place. And I’d say part of the CapEx, too, that included in the 1.8, 1.9 this year is us with longer lead times on some of the assets, we are buying some compression right now, which is longer lead time, which is actually for 2024. So part of it is us getting ready because I know there’s going to be future growth next year because lead times have been extended is pushing some more CapEx into this year as well. So part of it has been inflation, part of it is us trying to get ahead of kind of some of the supply chain disruptions and lead time growth.

John Mackay: All right. Thanks for the comment. Appreciate it.

Matt Meloy: Okay. Thanks John.

Operator: Thank you. Okay. One moment please. We have a technical difficulties on this side. All right. And our last question for today will be from Sunil Sibal with Seaport Global. Please proceed.

Sunil Sibal: Yes. Hi. Good morning, everybody.

Matt Meloy: Good morning.

Sunil Sibal: I just wanted to get a little bit of clarity on the returns on investments. I think a few years back, you had talked about a 5 to 7x kind of EBITDA multiple for gathering and processing capital spend. I was curious how that has changed in the current environment?

Jen Kneale: I think that we’ve actually seen an improvement in those returns, partially because as a result of, I think, being very capital efficient when we bring new projects online, they tend to be very well utilized, particularly on the gathering and processing side. So we’ve actually seen the returns improve just as a result of utilization as we try to get plants constructed as quickly as possible, but as Pat mentioned, sometimes have to operate the system overcapacity prior to a new plant coming online and/or utilized third-party offloads, that means that once the new plant is online, it tends to be very highly utilized or at least that has been our very recent history. And so I think that’s driving returns lower on that side of the business €“ returns higher on that side of the business, so multiples lower, sorry.

Matt Meloy: Yes. I’d say €“ just to add to that, I think as we think about going forward, 5% to 7% is still kind of what we think about and how we would articulate returns. We were able to execute better than that. If you look back over the last five years, closer to 4 times. And also part of that is we were successful in investments like, for example, GCX. We invested and we sold that at a significant multiple of capital, a really good return for us, and that kind of nets into the CapEx number. So we had some onetime items like that, which also helped drive that higher. But I think 5% to 7% is a good kind of planning case and we’ll of course try to beat that through optimizing, but 5% to 7% is a good point in case.

Sunil Sibal: Okay. Thanks for that. And then one clarification. I think in the past, you’ve talked about the spend on the compression and pipeline being 1:1 with a new builder processing plant cost. So I think on the previously in the call, you said $175 million is what a new typical processing plant is costing. So is that 1:1 thumbnail still good for the other capital to fill up the plant?

Matt Meloy: Yes. I think over time, that’s a reasonable assumption. I’d say now what we have been seeing recently is potentially even a little bit more capital efficient than that. So maybe a little bit less as some of our producers are being more efficient with where they’re drilling; so€“ but it can vary from year-to-year. So I’d say that’s not an unreasonable assumption. Maybe I’ll take the under on that. Maybe it’s a little bit less gathering and compression versus the $175 million to fill up a plant but it can vary from year-to-year as well.

Sunil Sibal: Got it. Thanks for that and congratulations on a good print.

Jen Kneale: Thanks Sunil.

Matt Meloy: Okay. Thank you.

Operator: Thank you. Ladies and gentlemen, this concludes our Q&A Session. I will turn the call back to Sanjay Lad for final remarks.

Sanjay Lad: Thank you, 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: Thank you, and everybody, this concludes today’s conference call. Thank you for participating, and you may now disconnect.