Kinetik Holdings Inc. (KNTK) Earnings Call Transcript & Summary

Good morning, and thank you for attending the Kinetik's Third Quarter 2022 Results Call. [Operator Instructions] I would now like to pass the conference over to your host, Maddie Wagner with Kinetik. Thank you. You may proceed.

Thank you. Good morning, and welcome to Kinetik's Third Quarter 2022 Earnings Conference Call. Here with me is our President and CEO, Jamie Welch, as well as Matt Wall, our COO; Anne Psencik, our Chief Strategy Officer; Steve Stellato, our CAO; Todd Carpenter, our General Counsel; Trevor Howard, our VP of Finance; and Chris Kendrick and Tyler Milam, our VPs of Commercial. The press release we issued yesterday, the slide presentation and access to the webcast for today's call are available at www.kinetik.com. Before we begin, I would like to remind all listeners that our remarks, including the question-and-answer section will provide forward-looking statements, and actual results could differ from what is described in these statements. These statements are not guarantees of future performance and involve a number of risks and assumptions. We may also provide certain performance measures that do not conform to U.S. GAAP. We provided schedules to reconcile these non-GAAP measures as part of our earnings press release. After our prepared remarks, we will open the call to Q&A. With that, I will turn the call over to Jamie.

Thank you, Maddie. Good morning, everyone, and thank you for joining us today. We reported our third quarter 2022 results yesterday afternoon, and I'm pleased to share with you this morning that we reported a record quarter with respect to both processed gas volumes and adjusted EBITDA. In this first year post merger, we have continued to improve quarter-over-quarter across all facets of our business as we realize integration synergies, optimize our system and grow customer relationships. Having grown 1.5 billion cubic feet per day through the end of September, the Permian Basin remains on track to grow natural gas volumes by 2 billion cubic feet per day exit to exit in 2022, with consultants expecting another 2 billion cubic feet per day of growth in 2023. Drilling down further, we estimate that the Delaware Basin accounts for well over half of total Permian supply growth. Moving a bit further downstream, we are beginning to see tightness at the long-haul residue gas transport outlets earlier than expected. In October, approximately 1.3 billion cubic feet per day of takeaway capacity was taken off-line for routine maintenance, which resulted in Waha moving into negative price territory, a stark reminder of the 2017 to 2020 Waha basis collapse. This recent event reinforced to us a few things. First, Permian natural gas takeaway appears to be fairly balanced and Waha pricing is volatile when utilization rates are this high. This point is further reinforced when looking at northbound natural gas volumes, historically viewed as a transport avenue of last resort, which in September and October, hit levels not seen since the in-service of Permian Highway Pipeline almost 3 years ago. As expected, the immediate supply response is already underway with Permian processes largely switching plants into recovery. With the takeaway supply-demand equation fairly balanced, further supply growth will likely only exacerbate discounted Waha prices. Second, the event highlighted how critical it is to differentiate ourselves from our peers by offering our customers integrated solutions. Even in the face of inflation and weaker commodity prices, the Permian Basin continues to grow and supply both the U.S. and the world's energy needs. The Permian rig count has remained steady at roughly 340 to 350 rigs since May despite a 20% reduction to WTI crude since then. In the third quarter, we, Kinetik, averaged approximately 17 rigs on our system and had approximately 70 wells turned to sales. We have continued to see a steady ramp of activity over the course of this year. In a basin where processing capacity and pipeline egress to the Gulf Coast are becoming tighter, Kinetik stands apart. As mentioned earlier, we are able to offer our customers processing capacity today and an evacuation route for residue gas to the Gulf Coast. As we move into 2023 and beyond, this only becomes more meaningful. Similar to our first and second quarter earnings results, many of the figures today will be reported on a pro forma basis, assuming the business combination between our predecessors, BCP and Altus closed on January 1 of this year. We believe it is more reflective of our actual results and provides our investors with more meaningful information and helps to reconcile our 2022 full year guidance. On Page 3, moving to our recent highlights. We reported a record adjusted EBITDA of $212.4 million for the third quarter. This was driven by increased gas volumes across our Midstream Logistics segment and stronger-than-expected contributions from our Pipeline Transportation segment. Our 2 previously announced gas gathering and processing agreements with large-cap investment-grade counterparties began on October 1st. Also, beginning November 1st, we commenced our new gathering and processing dedication with Apache for its DXL acreage in Central Reeves County. We have continued to identify both organic and/or inorganic growth opportunities. Year-to-date, we have added 6 new customers to our system, representing a 20% increase in overall customer count. In the third quarter alone, we added 3 new private customers. Not only have we added new customers, but we have expanded our relationships with existing ones. As I just mentioned, we have established relationships with several new private producers along our system. This is a net positive for us as these producers will pull inventory forward, accelerating development on our system into 2023. These teams have proven track records, and we look forward to being a part of their emerging growth story. In September, we acquired Brandywine NGL. This acquisition affords Kinetik greater control over system NGLs and provides interconnectivity to downstream natural gas liquids outlets. Kinetik NGL, our 250,000 barrel per day intrabasin NGL pipeline system is comprised of the Dew Point and Brandywine assets. It is wholly owned and operated by Kinetik. Progress continues on the 550 million cubic feet per day expansion of PHP. The required compression equipment has been secured and preconstruction activities are well underway to secure our construction contractors, land and other associated materials. The project remains on schedule to be in service by November 1, 2023. On Page 4, in the third quarter, we achieved a new quarterly record for gas processed volume at 1.2 billion cubic feet per day, representing a 4% increase year-over-year. Crude volumes gathered were approximately flat year-over-year at 67,000 barrels per day. Although we benefited from 25 wells turned in line on our crude system in the third quarter, that drove an 8,000 barrel a day increase in October over those third quarter average levels. Water gathered volumes were down approximately 11% quarter-over-quarter, simply due to producer recycling in July from our largest customer. The Diamond Cryo expansion of 120 million cubic feet per day of incremental capacity is on schedule for completion in the first quarter of next year. We have procured the long lead time equipment and kicked off construction. In June, we completed the super system interconnect, connecting the legacy BCP and Altus Systems. The Interconnect has allowed us to access latent capacity at Diamond Cryo and utilize the SRX technology available at Diamond Cryo to further enhance our NGL recoveries, achieving up to 99% ethane recovery. An additional benefit to the system interconnect and latent capacity is that we were recently able to temporarily bring several BCP facilities offline to perform routine maintenance without curtailing any processed gas volumes for our customers. This year, we will have replaced or avoided the addition of 32,000 horsepower of rental compression with 10 company-owned surplus compression units. Annualized, this translates to over $5 million of annual operating expense savings. In 2023, we will harvest additional synergies with the installation of own surplus front-end aiming treating equipment at the BCP complexes and continued compression relocation projects. Still on Page 4, on financials, we reported adjusted EBITDA of $212.4 million. We generated distributable cash flow of $158 million and free cash flow of $34 million. On October 19, we declared a $0.75 per share quarterly cash dividend, pro forma the June 2-for-1 stock split, representing a dividend coverage ratio of 1.5x. We exited the quarter with a 4x leverage ratio and remain confident in our ability to achieve our long-term leverage target of 3.5x. Our total capital expenditures for the quarter were $145 million, $84 million of which was associated with the Pipeline Transportation segment. On Page 4, we have provided some segment specifics. Our Midstream Logistics segment generated adjusted EBITDA of $137.5 million in the third quarter. Year-over-year, that segment pro forma adjusted EBITDA is up 25%. In the third quarter, we realized our full 2022 EBITDA synergy target of $25 million. This was achieved 3 months ahead of schedule. And as a result, we're increasing our 2022 synergy capture guidance to over $30 million, as shown on Page 7. Shifting to our Pipeline Transportation segment. We had a record quarter and beat our internal expectations. We generated an adjusted EBITDA of $78.7 million in the quarter. Moving to Pages 5 and 6. The strong third quarter and the fourth quarter outlook gives us confidence to reiterate our adjusted EBITDA and capital expenditure guidance. Our adjusted EBITDA guidance is $820 million to $840 million, with $830 million at the midpoint. Over the course of this year, we have realized adjusted EBITDA growth quarter-over-quarter. In the fourth quarter, we have a number of new gathering and processing agreements commencing. Our 2 previously announced gathering and processing agreements with large cap investment-grade parties commenced on October 1, and our Apache DXL agreement started last week on November 1. There are also several other new contracts with private producers that have or are about to commence. We will continue to further capture additional integration and cost synergies. Offsetting the sequential improvement in EBITDA is slightly weaker natural gas and NGL prices. Our capital expenditure guidance remains unchanged at $280 million to $300 million. This includes $170 million to $190 million of Midstream Logistics capital and $110 million of Pipeline Transportation capital. Our projects are both on budget and on schedule and are insulated from the inflationary environment as long lead time equipment and materials have been secured. Within our Pipeline Transportation segment, the $110 million guidance includes our total funding commitment to the PHP expansion for this year, the Brandywine acquisition and early spend on Delaware link. Our producer customers are currently in their budgeting season. And as a result, we will provide our 2023 EBITDA and capital expenditure guidance in February when we report our fourth quarter and full year 2022 results. If you go to Page 9, I'd like to provide a few updates before we move to Q&A. As we previously announced, we completed our comprehensive $3 billion refinancing in June. Most recently, we have locked in a fixed rate on our Term Loan A to May 2023. Specifically, $2 billion, the full amount of our Term Loan A bank facility is now fixed at a SOFR rate of 4.45%. And from May of '23, through May of '25 $1 billion is fixed at a SOFR rate of 4.46%. These actions taken together reduce our floating rate exposure to less than 15% of total current debt outstanding to May of next year and then approximately 40% thereafter through the maturity of the term loan A. We just marked the 1-year anniversary of our merger announcement. We commemorated this event at the New York Stock Exchange on October 24 with members of management and the Board at the opening bell ceremony. Looking back, we have remained steadfast and committed to executing upon the financial goals and strategy presented a year ago. We completed our 2022 capital allocation goals earlier this year, and we remain confident in achieving our 3.5x leverage target and securing investment-grade ratings by year-end 2023. Thank you again for your continued support and for joining us this morning. And with that, I'd like to open the lines for Q&A.

[Operator Instructions] The first question is from the line of Jeremy Tonet with JPMorgan.

And I just want to build on a little bit more as far as Permian takeaway is concerned. A few questions there, I guess. And just with PHP coming online, is that a distinct date where everything starts on day 1? Or could it be some of it be servicing volumes partial in service earlier than that? And if we think about later data takeaway, how would you think about the chances of GCX expansion versus Permian Pass versus another project coming to fruition?

You ask all the questions which are top of mind for everybody. So let me deal with PHP. So the short answer is there is always going to be a period for which there may be some incremental capacity. How much that is on a volumetric basis and what the period that is still TBD, right? It depends on when we're mechanically complete and the tie-ins are done. So I think it's a bit of a moving target. We'll keep you apprised, and I'm sure Kinder will too as we travel along this path on getting to an in-service date of November 1. So there could be some attractive upside. Don't get us wrong. We just don't know how to quite measure that at this point in time. As it relates to the overall takeaway capacity, I think third quarter next year we're anticipating the Whistler expansion to happen. Then obviously, November 1 will be PHP. The sum total of the 2 of that will add just over a Bcf. Then obviously, I think, going into '24, you've got Matterhorn. And so that will be interesting. However, if the pundits and the consultants and the experts are right, and we do hit 2 Bcf a day of growth for this year, and we hit 2 Bcf of gas growth for next year. I think it's going to really accelerate the discussions around incremental takeaway. And whether that's Warrior for transfer or anybody else, I think there are lots of projects out there trying to be commercialized. And I think it's just a case of waiting to get that balance when customers can clearly see the net benefit to them. I think, as we listen to one of our favorite customers, the guys at Permian Resources yesterday, the Waha negative price in October was a bit of a shocker. It felt like we were -- it was deja vu over again, living that 2017 to 2020 time frame. And so I really do think that may very much jumpstart some overall activities on the commercial side. Do I see it impacting GCX? Don't really know. It's hard to weigh that up. I don't really -- I'm not sure exactly whether a new pipeline, a new 42-inch is the right answer. I think it might be in the eyes and in the mind of many producers because the more steel on the ground, the more egress, the better as opposed to the same stick of pipe just having a larger volumetric throughput. But yes, that's -- it's hard to handicap.

Got it. That's helpful. Appreciate your thoughts always there. And turning to '23 and not running, front-running guidance there, but just wondering any incremental bread crumbs you can leave for us as far as how EBITDA could shake out? a lot of moving pieces there with growth and the new projects, what have you. But wanted to see, even with commodity price sensitivity, I guess, how you see direct commodity price sensitivity evolving over time? Or any thoughts to share with us on how that could impact 23?

So interestingly enough, I think the -- as we've been very consistent, you're in a commodity price environment where traditionally it's -- you have migrated from POP or POL contracts to traditional fixed fee. That's not to say that there's not some commodity upside with overall system performance, plant performance. The SRX technology, 99% ethane. I mean that is state-of-the-art. But the overall percentage of that as a contribution relative to the overall base fee that you would get from a customer is going to be on the lower end. And I think as we think about the overall expectation, our migration will be to more fixed, less POP and therefore less commodity sensitivity going forward. And certainly, the Pipeline Transportation component will also, as that continues to increase, that will continue to decline the overall contribution factor. As we look at 2023, landscape looks like this, really good growth, great contracts that are now, you're annualized, obviously, contracts that have started this -- the last part of 2000 and 2022, and you'll annualize them over 2023. You've got some really good pull-forward growth. I would say the interesting thing is the amount of private activity. I think we've seen what privates can do. We've all lived through this over the last several years where the publics have been very disciplined in their overall capital expenditures and all about returning cash back to shareholders and other stakeholders. And the privates really accelerating the inventory and capitalizing on that commodity price windfall. We've got 6 new customers, 3 we just signed up this past quarter, and we've got an accelerant right now going into '23, which is great. The headwind for '23 is commodity prices. And whether it's -- what's going to happen is when is Freeport going to come back online? What's going to happen with Waha pricing? How is this going to look relative to the overall growth because, as we said, if you do have 2 Bcf of growth with no incremental capacity until the September and in November, you've got 2 Bcf a day theoretically for 2023. And you've got only a Bcf coming online as far as takeaway capacity and that being Whistler and then obviously PHP towards the back end of that year of 2023. So I think there is -- we've got some really good puts and takes on the expense side, the OpEx side, we're really being mindful of how we think about compression costs. Salaries and benefits, much like the rest of the entire economy are obviously feeling some pressures because we've got people obviously thinking about their pocket book and disposable income. And synergies, right? Synergies, that $25 million already to be achieved by the third quarter and now increasing guidance to $30 million, we said originally it was going to be $50 million run rate. We said we're going to significantly beat that. So that $30 million is both a pull forward and I would say it is a micro snapshot of the potential to significantly increase that $50 million overall target.

The next question is from the line of Gabe Moreen with Mizuho.

Jamie, maybe if I could continue on the '23 outlook, seen just with all the activity and new customers you're signing up, can you talk about where things stand right now in terms of how you feel about processing capacity utilization, the length of these contracts and whether that gives you visibility to potential further expansions or even new builds? Maybe I'll just see where your thoughts are there?

So I think, Gabe, it has not been lost on us as we've seen all of the associated announcements around processing facilities being added late '23 into '24. So there's a little bit of a motto within this organization, which is time is now. We are selling this today. And as I said, the integrated solution is, we are a foundation shipper on PHP. We're a foundation shipper pro forma the expansion. We can start as people see what's going on with gas prices and whether they're private or public, there's a reticence to flare, they really want to find economic value for that side of the hydrocarbon stream. So I think it's very clear that we can offer something that differentiates. And we've got space today, right? These people are -- the privates are focused today. And we have capacity to give them today. So it's a very nice marriage. What does that mean as far as how we think about our processing, we're increasing the processing footprint by 120 million cubic feet a day for Diamond. So about from 600 to 720, as of late March of next year, that being 2023. And Matt and the engineering team have already been looking at the rest of the fleet. And we're seeing whether we can get 10% to 20% improvement across our larger cryos, which obviously would also be very low, low cost and nice immediate upside because we can make it happen immediately. We realized what is important to us. We want to sell out everything we can once we start getting within that 90% ZIP code, looking out sort of 6 months out at overall processing volumes relative to capacity. That's the point in time you will see us make decisions on what we do next on a processing plant. And just as importantly, where, where are we going? Like where exactly do we think? We wanted to go where the puck is going to be, not where it's necessarily at.

Thanks, Jamie. And then maybe if I could turn to commodity prices and hedges. You mentioned, I think, in your answer to Jeremy's question about trying to negotiate contracts to more fee-basis. Is that playing at all in your decision on hedges and just the latest also, I guess, between ethane rejection or not? Just wondering what the latest thinking is around hedging here.

We've been working on the operational hedging as it relates to 2023, so that would then determine whether we have plants running recovery or rejection. So that we've already been putting in place. As far as other fundamentals on the hedging side, we are looking acutely at all the potential opportunities that present themselves to in fact mitigate the hedging exposure and looking to make sure that we capitalize on what we think makes the most sense relative to our overall supply stack, meaning how do we think about growth that's coming on with different contracts because not every customer is the same and not every contract is the same. So we've got a lot of internal work going on, Trevor, Ross and Graham working with Anne Psencik on the NGL side. We've really been spending a lot of time and effort as we now really get headlong into our 2023 activity.

The next question is from the line of Neel Mitra with Bank of America.

First, just wanted to clarify your latent processing capacity going into 2023. Jamie, it sounds like you've landed some private agreements, and you haven't necessarily known the full amount. I think the last presentation said you had about 0.5 Bcf a day of latent capacity with the Diamond Cryo expansion included. Can you kind of give us your views on where you'll be in '23 with that -- with the existing customers?

Well, I think as we said, the 1.5 Bcf was a projected viewpoint in the context of the bigger contracts that we had just signed in the first quarter. And with the privates, obviously, we can aggregate them, they would obviously take of that remaining 0.5 Bcf. I would say, in total, I'm looking at, Trevor, wouldn't be more than 100, right? So I think you're looking at about 20% of that further being impacted. Good contracts, really good contracts from a fee and from an economic margin standpoint. And I think we probably risk those volumes a lot more heavily just because there is a sense of a little bit of the unknown.

Got it. Second question, you have a 56% interest in PHP expansion. I know you've contracted a little bit down with some of your 2 contracts that you announced earlier this year, but are you able to bundle G&P and takeaway agreements on that expansion going forward? Or are they going to be distinct contracts?

No, we will bundle it. And that was part of the commentary around continuing to do more things with our existing customers and some of the things we've done with them on gaining control of their residue gas which, as you know, Neel, firsthand. We have a couple of contracts where we do have some taken in-kind customers. There's one customer in particular that we've now got control of their residue going forward in exchange for which they get some very attractive Gulf Coast pricing.

Right. And a follow-up to that, do you see any flow assurance issues this time around in 2Q '23 just with the amount of gas that's coming out and the lack of takeaway capacity and the inability for a lot of guys to flare?

No. I don't think so, Permian.

Okay. And then sorry, just a last…

No. Sorry, I'm just -- are you talking about general Permian or are you talking about Kinetik specifically?

General Permian.

In terms of -- got it. Look, I mean, just given what we saw recently and if supply growth resumes and continues, there will -- I mean, yes, there's going to be concerns about the ability to actually go and move that gas out of the basin. Yes. But specifically with Kinetik, due to our downstream capacity arrangements as well as our marketing arrangements, we do not see a risk. And just further hammering on that point, in 2020, before PHP even came online when the basis was blown out, we didn't have any issues actually going physically flowing the gas. And it's fair to say -- Neel -- and -- hey, Neel, so I was going to -- sorry, I was going to say, as I said in my earlier remarks, we'll just be in recovery, right? And so there might be an impact in the context of what happens with ethane pricing, sure. But obviously, that's one of the first triggers that I would say self-help that you can actually utilize.

Got it. And if I could just ask one more on your view of NGL takeaway tightness. You've seen Shin Oak postpone a year, Daytona announced on the Targa system to come on in 2024. So looks like different systems have different views of tightness. You're obviously involved or could be involved in ownership with both and have capacity on both. What are you seeing in terms of tightness when we need it or if there's pockets that are tighter than others within the Permian?

Look, I would say on the Shin Oak side we see more broadly from a market perspective, 2025, we really start to see some very some very interesting elements affecting the market. And that's when obviously we really do see a need for the incremental takeaway capacity. The Shin Oak expansion, as Enterprise has said, is ready to go. They are trying to work out Phase 1, Phase 2, what does it look like? And they're listing -- engaged in conversations with their customers. They're thinking about what they have with their own footprint. They're also talking to us as their partner in the context of trying to work out what it is we want to do. And so I think we saw the Daytona, I think there obviously it's a different discussion. And obviously, that should -- obviously that gives us cause for optimism, I think, around the overall Targa expectation on volumes and their continued customer growth. So I think that we're okay for now -- and I think you're okay as you go through next year into 2024. And 2025 is when certainly we think that Shin Oak needs to be in service just given the combined needs of the existing 2 partners, and we can't really comment on what Targa is thinking as it relates to the timing on Daytona.

The next question is from the line of Michael Cusimano with Pickering Energy Partners.

I wanted to start on CapEx for '23. I was hoping you can go through some of the puts and takes there rolling in from 2022 and how maybe like the Shin Oak delay affects what you were looking for '23?

Shin Oak delay probably means that there's less spend in '23 which is good. I'll call that a good guy. We've got PHP expansion, so knocking down the bigger buckets. We've got treating as it relates to the carryover. So you've got the front-end surplus amine treating at our existing BCP sites. So that's a -- that was a modestly large capital item on the Midstream Logistics side. We'll have well connects. We're obviously going through all of that. Delaware Link, which is the 30-inch 40 miles residue gas, which is fully sold out and then feeds into PHP and the expansion on PHP. So we've got the Delaware Link piece. You're going to have the PHP expansion piece. And we've got -- just in the context, 75% of our PHP spend is to be spent in '23 because 25% was this year. And you're looking at -- I think it's around $425 million, $430 million of total cost, 88. So that's some of the bigger items. I think that's probably the biggest ones that I can tell you, and then the unknown is exactly how much we end up having to spend at Shin Oak. You've got a little bit of maintenance. We've told you $14 million, $15 million on the maintenance side. You've got some base growth with the -- just our overall customer footprint, which obviously continues to expand. They're not huge dollars, but just little bits and pieces, right? But everything obviously adds up.

Okay. That's really helpful. And then it seems many in the industry are pointing to ethane recovery as being the option to free up some gas takeaway. But I'm wondering if you have a view on how that affects ethane markets in Belvieu and if that puts additional pressure there?

All right. So why don't I get you -- I'll let all of you have the opportunity to talk to Anne Psencik, who is our resident NGL expert, and she can give you her perspectives on the ethane market.

It will put some pressure on the ethane market just because of the petrochemicals right now are not performing very well. I mean there's not a lot of demand in with China not pulling like they used to. We're going to see pressure on ethane. But I do believe that you'll find that the midstream -- the integrated midstream will be able to deal with the ethane that shows up in Mont Belvieu, they'll export it out. I know right now they're full and there are issues with shipping. But all of them are working on it to try and make sure that we get more out of the market.

But it will put some pressure on pricing, right?

It will put some pressure on pricing.

Because you have -- I think universally you will have everyone be in recovery. And that obviously, just that incremental ethane in the stream will obviously put some pressure despite whether you can export it or debottleneck existing impacts on the overall demand chain.

The next question is from the line of Jackie Koletas with Goldman Sachs.

So you guys moved forward on the Brandywine MDL acquisition. You're also working on the Delaware Link project. Are there any other opportunities like these around the footprint, either on the bolt-on M&A side or on the organic CapEx side? I think there is -- there are always more things that we can do. The Brandywine to us was about security of supply and ensuring that we control the NGLs. The NGLs coming out of Diamond Cryo. We do -- yes, obviously out there is the potential related to our major shareholder dropping down their 25% or engaging in a discussion with us about dropping down the 25% in Grand Prix. Grand Prix is obviously now Grand Prix plus Daytona expansion. So I do think there are some other bits and pieces, Jackie, that are out there, relatively modest in size. As far as other merchant acquisition opportunities, I think we've been very consistent on the G&P side. It's got to fit our proverbial pistol. It's got to be something that we see is tremendously value-accretive. It's additive to who we are and what we do. And that means that collectively from a commercial standpoint, from an NGL standpoint, a residue standpoint, operational standpoint. And when I say commercial, that's on the customer side and the types of customer contracts that we all collectively believe this business is worth, that opportunity is worth more in our hands than on a stand-alone basis. We haven't found anything that really fits that criteria. So we're being very, very strict in how we think about things. And I think we've got enough growth organically here to keep us so fully occupied that I would say none of us are just sitting idling our thumbs.

[Operator Instructions] The next question is a follow-up from the line of Jeremy Tonet with JPMorgan.

Just want to shift a little bit. I know it's a very small part of the portfolio, but EPIC, just wondering what's your latest thoughts there and outlook, I guess, on that asset?

Trevor, would you like to give some thoughts, or Anne?

Yes. I mean I'm happy to jump in here. Thanks for the question, Jeremy. Look, on EPIC Crude, as you noted, it's a small part of our business. When you look at the outlook for Permian crude production growth and the contract profile, margins and volumes should continue to expand. The pipeline is actually running pretty full. So from here, it's more of a margin expansion game. And due to their contract nature, it really is going to follow what that spread between MEH and Midland looks like. And so when you look at the forwards, it's continuing to widen, which should be a good thing for the pipeline. And so we see margin expansion on that business for the next several years. But as we look at it from today, we're still not seeing distributions coming out of it in 2023, and that's what we're prepared to comment on today.

Got it. That makes sense. I mean, maybe it's not something to talk about at this point, but just wondering, is that an asset that you could see more capital going into? Or is the cap structure kind of sustainable as it is? Just kind of curious on that side.

I think if margins continue to -- if you see the net improvement that we've had, there has been net improvement this year, just so I may be very clear. And I think where they started the year and where they're finishing the year are 2 very different places. That should keep, make sure that it can deal with its own capital profile. Obviously there's complete uncertainty of what happens '24, 2025. They've got debt that comes due. I mean there's a lot of things and a lot of unknown and unknowable elements to the overall prospects for that pipeline. So we're just -- as we have, we've written that investment down to 0. And as Trevor have noted, we have no anticipation of any distributions coming, nor do we have any viewpoint that there will be any further capital committed.

Got it. That's helpful there. And if I could ask just one last one, and it's been touched on the call in a number of different ways. But was just curious, as you look forward now in your area in the Permian, there's a lot of tailwinds and headwinds for production growth. But do you see upside or downside to current upstream budgets and production targets at this point, just given the great resource versus potential takeaway issues next year?

I think you continue to see modest growth. I don't think suddenly 2023 is going to show up and everyone is going to open up the safe and take all the money out and basically put it back in the drilling. I think that we have seen a change of behavior. The nice thing is you can still get lots of growth, we get a lot more gas growth. The decline rates, crude, 70% year-over-year. It's only 50% for gas. That's what's creating all of the gas. And that is going up. So we're seeing gassier and gassier benches and formations, obviously now starting to be actually overall exploited. And with obviously a lot of private folks back at it, I think you're going to see the cycle of smaller folks grow, grow acreage positions and then we'll fold into public and life cycle will start again. And that's what we're seeing. So I think that's a really -- that's a nice dimension to have as a backdrop for '23.

And Jeremy, I'll just add on that. One thing is unless you see a supply response on the services side, just given where costs are, it's hard for us to see rig counts materially moving higher. I mean they've been relatively flat for the last 6 months. And like I said, unless there's a change to the supply-demand dynamics with services in the basin, it's hard to see us break out from that number from here.

[Operator Instructions] As there are no remaining questions in queue, this concludes today's conference call. Thank you for joining today's call. Please enjoy the rest of your day.

Thank you.