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2026.09.30 | TB | Energy | Delek Logistics Delaware Basin Growth

原标题：Delek Logistics – Delaware Basin Growth & Infrastructure Constraints

#energy

Third Bridge · 2026-09-30

Analyst-led • 17 Sep 2026

Companies: DKL US

Matt Tate (MT) VP, Business Development at Dakota Midstream LLC

Curren Larson (CL) — Third Bridge Sector Analyst

Agenda

Key Insights

Introduction

CL [00:00:02]: Welcome to Third Bridge's Interview entitled Delek Logistics – Delaware Basin Growth & Infrastructure Constraints. I'm Curren Larson, and I will be facilitating today's Interview with Mr Matt Tate, former Senior Director of Business Development at Delek Logistics.

Matt, before we start today's Interview, please state I agree or I disagree to the following statement: You understand the definition of material non-public information and agree not to disclose any such information, or any other information which is confidential, during this Interview.

MT [00:00:30]: I agree.

CL [00:00:34]: Could you briefly introduce yourself?

MT [00:00:41]: Matt Tate, formerly Senior Director of Business Development at Delek Logistics, where I worked primarily on the produced water and on the natural gas gathering side. I'm now currently Vice President, Commercial for a Bakken operator in the midstream side as well.

Questions

00:01:06] How are you thinking about the durability of the recent volume momentum across the Delaware footprint, given the improving Waha outlook and expected new takeaway capacity over the course of 2026-27?

MT [00:01:36]: That's the beauty of the Delaware. It continues to be a very resilient basin. Capacity constraints, both on the gas and crude side have started to get alleviated as basically wellhead to Gulf infrastructure has started coming online, but a lot of that is being supported by additional LNG export capacity coming online in the Gulf as well. All of that is basically making production in the Delaware even more economic than it already was. Then in addition to that, you're seeing more consolidation, which sometimes you can see that lead to slower drilling as guys become a little bit more conservative, but with the Delaware Basin really being the best liquids play in onshore US, it gets to the top of the totem pole for every operator that has exposure there. I think we can all expect that growth to continue to go on at a very quick pace. I think there's between Midland and Delaware Basin, I think over almost 400 rigs still operating in the area today. Growth is going to continue to happen there.

00:03:04] Rig count has expanded in 2026 and commodity pricing remains high. Within the positive outlook, what do you see today as the primary constraints on sustaining volume growth over the next 2-3 years? Is there anything on the downside that you'd keep watching, or is the outlook truly positive and blue skies over the next three years?

MT [00:03:45]: It's going to continue. It's like every time you get takeaway infrastructure coming online, that will alleviate some constraints, but as production grows and as people push production to newer areas, infrastructure can continue to be a bottleneck. The Delaware Basin really saw its first round of major growth in the COVID era in that Stateline area, right down in Texas, New Mexico Stateline. That's still a very, very heavily active area, but you're starting to see operators slowly pushing further north into the Delaware Basin, further north in Eddy County and Lea County. Those are areas where there's not as much infrastructure as you're going to see in that Stateline area. I think you're going to see some constraints on the in-basin gathering side. Some of that's going to be due to just the infrastructure itself, getting gas pipelines in, getting water pipelines and getting water capacity. That's a big one is figuring out what people are going to do with all the produced water that keeps growing as water-to-oil ratios are increasing and then handling the sourness of the production. H2S levels are rising, and they're going to keep rising because we're now getting into production that's H2S. It's not necessarily a result of artificial origin in terms of something that man created as we were drilling this stuff. This is natural H2S. It's in the formation that we're seeing more and more of it.

00:05:30] From what you're seeing in the market today, aside from simply capacity, what determines which midstream operator wins new producer business in the Delaware?

MT [00:06:03]: Number one, a lot of these guys are already dedicated, but if they're not already dedicated, then typically, they're going to go out to RFP and they're going to send that out to half a dozen or so different midstream operators and midstream operators are going to put together a bid package. That bid package is going to be reflective of the CAPEX that's required to provide that solution, and there's going to be a fee commensurate with that. At the end of the day, proximity to infrastructure is the most sensitive factor in determining who's going to win a package. Proximity to infrastructure and then available capacity to take it. You take your typical gas processor in the basin. If they have excess capacity on their plant, then they're going to be very aggressive on getting production into their plant, whereas if you have someone where their plant is running full and they're looking at having to add new capacity, now they're looking at major greenfield underwriting, and that may be a different bid proposition for them, but I'd say, proximity and available capacity is going to be your major determinants.

00:07:21] You mentioned increasing water-to-oil ratios. In our previous Third Bridge Interview [see Delek Logistics – Permian Water Midstream Expansion Strategy & Integration – 9 January 2026], you mentioned that New Mexico's water capacity is structurally undersized. What are the barriers to organic expansion in terms of water capacity, especially in the Western Texas and Eastern New Mexico region? Under what circumstances would M&A become the more attractive path relative to organic growth to capture that volume?

MT [00:07:58]: What makes New Mexico a little bit unique relative to Texas, capacity in New Mexico is a lot harder to come by. Historically, guys went really deep into the Devonian formations or they went to the shallower zones, which you would call the DMG in that area of the Permian. The problem is that the regulators have almost made it impossible to get Devonian infrastructure in place anymore. It's not entirely impossible, but it's a very, very long permitting process and a lot of times, it ends in defeat for the operators. New Mexico regulators rightly so are very concerned about deep formation pressurisation that can lead to seismicity. That's a major issue. Then for the DMG, there are several issues there. One is you've got to find an area where the DMG makes sense. It's not everywhere. Then once again, getting regulators to approve that can be challenging. They're becoming increasingly more concerned with communication between disposal zones and production zones. That can be a challenge for getting DMG capacity.

Then there is a little bit of San Andres capacity on the far eastern side of New Mexico. It's a little bit more limited, but it is there, but the challenge once again there is there have been some major issues with people disposing into that zone because it's a very shallow San Andres zone where there have been hazards in terms of them actually communicating with existing conventional production and watering out conventional oil and gas, which would be disastrous for regulators because that robs them of their tax revenue. It's just a very tight area. Most of the disposal capacity in that shallower zone that's there is pretty much spoken for today. What that leads to is operators, if they need capacity quick, what they're left with is, "Okay, I've got to go buy somebody that has excess capacity," which, today, there's been a lot of consolidation. Today, the types of assets where you're going to see that, a lot of that's producer-owned assets, which some producers are willing to part ways with their assets. Others view that as having a very heavy premium, and it's more valuable to them to control their destiny, and they'd rather hang on to that capacity even if they're acknowledging that, "Hey, they've got excess capacity where there's basically unrealised value. That's always an option."

Then outside of M&A within particularly New Mexico, your last option is to pipe it out of New Mexico and get it into Texas. That's what we've seen a lot with operators with WaterBridge having their open season to build out in Andrews County. Western Midstream is basically doing the same thing. Goodnight is doing a variation of that, but just staying for the most part, just on the New Mexico side of the Stateline, but basically transporting that water out of New Mexico has almost become the last option, but the most practical option to getting capacity for operators there.

00:11:40] We're seeing a lot of consolidation. What is the cost of the incremental capacity today? How much capital would you expect to be necessary to add roughly 50,000 barrels per day of capacity either through acquisition or infrastructure upgrades?

MT [00:12:05]: It can depend on a number of different things. If you're able to get a permit in New Mexico and add capacity, a shallower DMG well is typically going to run around USD 7m-8m, but you're looking at 20,000-25,000 per day capacity on one of those, that would be a good one. If you needed 50,000, you need to double that. That's potentially USD 15m. If you can get a DMG permit, DMG wells can perform really well. Some of them can dispose them up to 40,000 barrels per day or higher, but those are much weak (audio cuts out 12.52-13.11). You have Devonian SWDs. You've got a good one, if you get it done right, USD 10m-12m. Hopefully, you'd get at least 30,000 barrels per day of capacity out of that, if not more. That's the way operators think about it. A good rule of thumb is that for every barrel of capacity per day, it's about USD 350, if not more. If you were to take a 20,000-barrel-per-day SWD, then your hope is that you can get that in the ground for USD 7m. That's obviously if you can get permitted capacity online.

Now, if you're having what you're seeing operators do now, like, say, let's talk about WaterBridge, what they're doing with their Speedway pipeline. They're designing a pipeline that can move hundreds of thousands of barrels per day into largely existing capacity that they have in New Mexico on SWDs that sit on surface property that are owned by their affiliate LandBridge. That's the major value proposition that they can offer is, "Hey, guys, I'm not having to go and pray that I get a new permit or spend all this money to put in disposal wells in New Mexico. I'm just going to build a pipeline, and I'm going to move hundreds of thousands of barrels per day to existing capacity that I already have in Texas." If those guys are able to sign up and get that scale to do that, then that can be substantially cheaper than going and continuing to put in new disposal wells.

CL [00:14:57]: I was thinking about it from the standpoint of what type of moat the Speedway has. If I'm understanding this correctly, you said it's not impossible to get a permit for an SWD [saltwater disposal] well, but it's nearly impossible today.

MT [00:15:18]: On the deep ones, yes. Then on the DMG ones, you've got to just be in the right area and give yourself 12-18 months because it's going to take some time. Whereas Speedway, it's just a matter of getting your pipeline built out, basically agreeing with your landowners on what right-of-way fees you have to pay them in building that pipeline. The potential size of the system is massive, but they could handle a lot of production in that area with, call it, about 50 miles of pipeline. Now, they're doing large dual 20-inch lines, but they should be able to do that for, call it, USD 2m per mile, maybe less. If you were doing that on and that was tying into basically 20-or-so SWDs that you have on the Texas side of the Stateline and maybe even 500,000 barrels per day, which I believe is what they're still targeting, that starts to make a lot of sense.

00:16:38] On the Midland side, Delek's management reported a 24% QoQ increase in water volumes, with some of the growth attributed to freshwater sales, but from an operational perspective, how sustainable is that growth trajectory without significant incremental capital deployment?

MT [00:17:04]: If you're talking about just Delek in general, company-wide, a lot of the growth that they've been seeing YoY has just been driven by the drop-downs that they've been doing. On the Midland side, on their water volumes, for the most part, their assets are largely around Howard County. Howard County is, I would say, easily in the eighth and ninth inning of available inventory. There's just not a lot of future growth left in that area where a lot of their assets are. They've built out a really good asset there, but there's just not a lot of growth left. A lot of their growth has been focused on the north side of Howard County, which is getting into tier-2, tier-3 acreage. I think you're at some point, going to start seeing those volumes really start to follow a PDP natural decline in fairly short order.

00:00:15] Operators are shifting towards multiple smaller SWD [saltwater disposal] facilities to mitigate the seismicity. You had previously estimated a 20-25% increase in SWD spending by having to do more, given less depth. How does this structural shift affect Delek's unit economics and capital intensity over the next two years, aside from Speedway?

MT [00:19:07]: For Delek, in particular, for produced water, most of their produced water assets, the vast majority of their produced water assets are in the Midland Basin, mostly in Howard County. I would make the argument that for the growth that I would expect for that area or for the inventory that's remaining in that part of the basin, their current asset footprint is more than enough to handle it. They shouldn't have to spend a lot on new disposal capital, maybe additional pipeline, but they're, for the most part, in an area that sits outside of the SRAs, the seismic response areas. They haven't been heavily affected by that. They've got a very large pipeline system that covers most of the county. Their capacity is pretty much sufficient to handle any additional growth that would come to that area. I don't see their Midland Basin water volumes exceeding what they have capacity for, absent them doing some kind of major step out and getting into a new area in Martin County, Midland County or maybe further down to Glasscock County.

Now on the New Mexico side, they've got their smaller water asset that they picked up from 3Bear. That is an asset where I think there could be some pretty significant growth, but for the reasons that we've discussed, it's in an area where the deep disposal zones are challenging and then the shallower zones are possible, but you got to be in the right area and give yourself enough time to get that capacity. All that to say, the smaller disposal facilities that I was mentioning was more so in regards to the tighter pressured-up areas on the Midland Basin side, but for Delek, I don't think that's really going to be a factor. I think that's more so for your guys that are really trying to compete heavily in Midland County and in Martin County, where there's a lot of remaining inventory left, but you're already seeing substantial reservoir pressurisation.

CL [00:21:34]: In Lea and Eddy counties, do you not imagine that the upstream would outpace Delek's existing gathering and water handling infrastructure?

MT [00:21:45]: No, in Lea and Eddy County, it already is outpacing their infrastructure, their gathering volumes, their disposal volumes. You can see that on their public records. That is an area of growth where they need to be looking at investing in that area alongside their gas infrastructure because wisely, they're continuing to really highlight the investments in their gas infrastructure, but they really got to also focus on growing water and crude alongside that because their growth is going to be driven on the gas side for that area, but in order to do that, for a lot of the reasons that we've discussed here, to get that capacity, drilling another SWD is probably not your best option. Your best option probably is sign up for takeaway on something like Speedway or look at acquiring operators that are in and around them in Northern Lea County. I think that would be their best option vs going and trying to put new SWDs in the ground.

00:23:02] Delek's management is expecting a step change in gas volumes through 2026, especially as the Libby sour gas solution is completed, but from a higher-level view, operationally, what is the realistic timeline from commissioning an AGI [acid gas injection] well and compression stations to reaching peak utilisation? How long would you expect that to take in the current environment?

MT [00:23:31]: It can take quite a while. They bought* Libby 1, and they finally got Libby 2 online. Obviously, they've been talking publicly about Libby 3. I'd say for budgeting purposes, you really need to think about 18-24 months to get a new gas processing asset online. That's just the basic processing set-up. The AGI wells can increase that significantly. An AGI is essentially just an SWD on steroids with an amine unit strapped to the front end of it. I'd say for timing purposes, I would easily factor in 18-24 months, probably close to 24 months to get sour processing capacity online.

*Expert mis-spoke. Delek built Libby 1.]

00:24:33] You had previously highlighted that the additional operating complexity associated with the highly corrosive gas sour stream is conducive to higher OPEX. Relative to a standard sweet gas plant, how much higher would you expect maintenance and labour costs and overall OPEX to be for an AGI facility?

MT [00:25:08]: It's more just additive. It's not necessarily that you're comparing the two because what you're basically doing is you're gathering sour production in the field. You've got to go build out, so It's higher on OPEX, it's higher on CAPEX. Number one, you got to go build out a dedicated pipeline to take sour production. You cannot take a pipeline that gathers sweet production and then also use that to gather sour production. It just doesn't work. You've got to have a dedicated line, even if it's paralleling a sweet line, you've got to have a dedicated line for sour. Number one, you got to build that out. Number two, then you've got to have compressors that are anti-rated [sic] to handle sour production. These compressors are much more expensive than a standard compressor. The operation of it is not necessarily that much different, but they are much more expensive. They're very hard to come by right now. You can be in quite a long queue if you're trying to buy one. If you're renting one, you can maybe get that in quicker, but these types of compressors are getting harder to come by. You've got higher CAPEX in your gathering, higher CAPEX on your compression. Then once you get it to your facility and you have an amine unit and an AGI well, you're basically taking that sour production, you're stripping out the bad stuff.

On the back end of that process, you've got a sweet gas stream that goes to your existing plant as sweet gas and then, basically, your waste, the H2S and CO2 that you've stripped out of that then go downhole into your AGI. You're effectively creating a new operation within your business. It's a new asset, new operation. You've got to have operators that are dedicated to it. Your labour cost is going to go up. Their standard of operating is going to be very different. A lot of instances, these guys are having to be fully masked up with gas mask as they're going and handling this stuff. It's not so much that it's increasing your plant OPEX, but you're adding a new operating asset into your footprint. How to price that can be challenging. I'd say your typical variable OPEX, not including processing, but your typical gathering compression OPEX on a gas asset out there in the Delaware can typically be USD 0.30-0.40 an M. If you're having to then run an amine unit and an AGI on top of that, you can easily triple that, easily triple that. Now obviously, scale is going to matter. The more volume that you can push, the more you can get that OPEX down, but yes, it can add significant cost to your gathering and compression side and the treating side.

CL [00:28:33]: Are we seeing a premium associated with handling sour gas that offsets the higher OPEX and even more, or is it about in line?

MT [00:28:41]: Yes, even more. Your margins on the treating side are some of the best margins in the basin right now.

CL [00:28:56]: If we continue to see the Delaware Basin trend increasingly sour, where does the Libby complex reach its practical processing limit? What would a brownfield L3 expansion require in terms of capital and timeline? Is that what you had said earlier, 18-24 months, or is it 12-18 months?

MT [00:29:20]: I would say just to get more processing capacity online, you can do that in 12-18 months, but to get a new AGI permit to get that foot in the ground, to get an amine unit, I would say that's going to be closer to that 18-24-month timeframe. They already have had a permit on their first AGI well. They had two permits actually. I think for them to go and get a new AGI permit, that could take quite a bit of time. It's quite a regulatory process to get those in place. This is assuming that you don't do things as we won't have to go down this, but if you do things in the Class 6 AGI well, that's going to increase your timeframe substantially. These are basically AGI wells on steroids that allow you to claim carbon offset credits. Typically, it's more in the waste management space, but those permits can take quite a long time to get.

CL [00:30:34]: How do you weigh the trade-offs of sour gas processing in the environment today of going for that?

MT [00:30:41]: I think in terms of getting more sour gas infrastructure in place, I think if you're a serious operator, that needs to be at the top of your list. As rigs are shifting more north, sour production is going to continue to increase and the basin is woefully undersized right now for sour treatment infrastructure. This was the whole thesis for operators like Piñon Midstream when they came in and built out the treatment infrastructure that they put in the ground and sold for, I think, like a 12x multiple. It's an area that's going to continue to be challenging. It's expensive to get into. What makes, I think, Delek attractive here and what gives them some tailwind to do this is they've got great contracts in place. Those contracts, a lot of that includes acreage that is fairly sour and trending sour. They just need to execute on that and get more of that capacity online.

00:31:57] You emphasised the three-stream platform, crude, gas and water, as a competitive advantage. How often are producers signing integrated three-stream dedications vs treating them as entirely separate commercial negotiations?

MT [00:32:18]: Honestly, it depends on the operator. I think there's definitely an advantage to it. From a CAPEX standpoint, there are certainly synergies when you can put three streams in a ditch and manage that process internally with one engineering team, with one inspector. There are definitely CAPEX advantages to doing that, and you're able to reflect that on the pricing that you offer to customers. The challenging part is you as the midstream operator have the ability to actually offer all of those three streams. If you're going to go and sign up new gas, you're also going to have the capacity for the water and the capacity for the oil. I think that's where it can get challenging for three-stream operators is you can sign up one, but you need to make sure before you say, "I can offer three streams," you need to make sure you have capacity for the other as well, but producers definitely appreciate it. They absolutely appreciate it because they typically see a little bit better competitive pricing. A lot of times now, you'll have your operators, typically, what you'll see is your marketers now are handling crude and gas and then you'll have a separate team that handles the water side. Sometimes that's an operations guy, sometimes it's a facilities engineer, but it's not a huge effort to basically get those two sides together and evaluate the proposal in a collaborative manner.

CL [00:34:07]: How much of a pricing concession are you offering in the midstream if you're doing all three streams in contract?

MT [00:34:20]: It's more so not about offering the concession, it's more so about being able to give competitive pricing but reduce our CAPEX in the process of doing that. It gives us the ability to be a little bit more competitive, but I would not say that your typical three-stream midstream guys just offering that on the front end unless they have to. Sometimes what you'll see is, "Hey, look, here's your fees all in standalone buckets. Here's what the fee structure looks like if you give me all three," but it's usually not massive concessions. It's usually something that allows both sides to win.

00:35:11] Are there any particular operational failures or bottlenecks in ramping up the sour gas treating process that you think is worth highlighting to an investor audience when you think about the downside risk to the projected volume ramp in 2027?

MT [00:35:35]: I think it's just understanding what's required to do it. As I was saying earlier, when you start taking sour production, you're not just necessarily piggybacking off of your existing assets. The only thing that you can really piggyback off of is your processing plant, but your pipeline gathering is going to be completely new. You can't just piggyback. You could have the biggest gathering system out there, but if it's built to take sweet production, then that's what it's going to take. You can't just start taking sour production. Then your compression. You may have six compressor stations, most of which out there today is not anti-rated for sour gas. Now you're looking at either changing out your compressors or installing new compressor sites that are properly rated for sour production. There's significant capital required to take sour production in addition to whatever existing sweet production that you have. I think investors really need to think about that. I think as people look at evaluating midstream operators and they're looking at maps that show, "Okay, here's our dedicated acreage, here's what we have. Here's our pipeline system." You almost have to look at sour and sweet as two separate things and really have a good understanding as to where that sour production is coming from and where it's expected to come from in the future because just because you have sweet infrastructure in the area, it doesn't mean you're going to be in a position to handle that.

00:37:34] Delek is putting about USD 180m-190m into the growth projects in 2026 and targeting up to USD 75m in run-rate EBITDA. Where do you see the biggest risk to getting the returns the company expects from that investment? Is there anything around these growth projects that you think is worth highlighting?

MT [00:38:03]: Without knowing exactly where they were bucketing all of that capital towards, I would say that dollars spent in the Midland Basin are going to be pretty challenged. Just on the crude side, just across the Midland Basin, margins have really, on the gathering side, at least, started to compress. People are just getting more and more aggressive on the crude gathering side where you're not making a lot of margin on the gathering side, and they're really just banking on downstream infrastructure and marketing capabilities in order to make up that margin. That's going to be challenged for a company where they don't have a massive downstream marketing platform. They're really relying on one key takeaway point and then a local refinery. That's great, but I think the question is whether or not they're going to be able to compete with the likes of the Plains and the Enterprises of the world that just have such an integrated wellhead-to-Gulf infrastructure network.

The New Mexico side is absolutely poised for major growth potential. That's where so many people are competing. I think they've got to figure out what types of investments are going to drive returns and then what's going to drive returns for the rest of their asset classes. If I can go and sign up new dedications for sour gas infrastructure, you need to start thinking about how there's going to be demand for that. How can I use that to then grow my crude gathering business and to grow my water gathering business? What investments do they need to make to expand that, particularly on the water side? Delek has got a solid crude footprint there with pretty solid capacity, but water in New Mexico is extremely challenged. I think any dollar they can spend to increase their ability to handle more water in New Mexico is going to be a dollar well-spent. It would be much wiser for them to focus on dollars in New Mexico than dollars in the Midland Basin for sure.

00:40:45] Is there anything about commercial contracts that you think investors perhaps misunderstand? Is there anything that provides downside protection to cash flow that we don't necessarily give credit for? What is overlooked around contracts even when you consider acreage dedications and MVCs [minimum volume commitments]?

MT [00:41:17]: The acreage dedications are the standard method of dedication today. The downside to that is you wear the drilling risk. The upside to that is even if new drilling slows down, you're still getting the PDP, so the production that's online and flowing that comes with that. That's the beauty of midstream. It's a heavy asset annuity type investment vehicle, where you are funnelling cash into assets that are going to bring more new production into your system that's going to increase that PDP wedge. Even when drilling slows down, you still have a declining PDP wedge that is going to continue to produce good cash flow for you so long as you're managing the rest of your business well, such as your debt and your expenses. To a lesser degree, Delek and other midstream operators are going to have MVCs, but today, the days of long-term MVCs that run on a daily basis are pretty much gone. You just don't see those in the industry much at all anymore.

Typically, what you'll see an MVC being used for is, "Okay, I've got a project that I've got to bring online by a finite date and that project is going to cost X and I need to make a return on that within 24 months." That's typically where you'll see an MVC that can be used to basically underwrite all of that or at least underwrite a portion of that, but it's not an MVC that just runs in the perpetuity for the term of the agreement. Typically, it has a finite date or a finite volume and once it hits that, it goes away. I'd say for the most part in the industry today, that's what you're seeing are acreage dedications. If there's some significant new greenfield project that is required for that particular operator, sometimes you'll see a finite MVC help underwrite that particular asset. That could be a new SWD, a new compressor station, but that's typically what you'll see.

CL [00:43:41]: Could you elaborate on why that is? What would it take to start seeing more MVCs in the longer term, or is that out, given both sides?

MT [00:00:17]: It's kind of out. Upstream guys got just absolutely hosed on those. When shale was really getting hot and heavy and taking off in 2014-16, that timeframe, I think there was absolutely no infrastructure out there hardly that was built to handle unconventional shale. Upstream operators were just basically signing up for anything that would basically get a pathway to market in the ground ASAP. That's what happened. The problem was as we went through these downswings, particularly as you saw in COVID, upstream operators were getting pummelled by these MVCs where the daily MVC was X, they were delivering at Y, which was some fraction of X. They were just paying these fees for capacity that they weren't using because the economics on the upstream side did not make sense to produce a well. They were paying money for capacity that they couldn't utilise. They couldn't even afford to utilise. Coming out of COVID, you really just saw those start to go away materially. Today, there's just been so much consolidation and the market just become so competitive on the midstream side.

There's more education now on the reservoir. As midstream operators, we're not looking at an acreage area and saying, "Man, geez, I don't know if this is going to work out. I better put an MVC in place to make sure I don't lose on this." We have such good education now on reservoirs and breakevens in particular areas that we feel much, much more comfortable now underwriting our infrastructure on an acreage dedication because we can develop a degree of confidence as to whether or not an acreage area is going to get developed. If I'm talking to Conoco about a particular area, I can look at that acreage, I can evaluate it, understand based off the breakevens, where that acreage likely sits relative to the rest of Conoco's acreage. If I think that it's a super-attractive area, then I'm going to be fine leaning in and saying, "You know what, okay, let's just do an acreage dedication. I don't need to take an MVC on this. I'm confident that you're going to drill this." That's really what you're seeing now on the midstream side gatherers.

00:46:45] Looking across Delek's current portfolio, where do you see the most pricing power for the company? Where does it have infrastructure that's valuable enough to pay a premium for it?

MT [00:46:59]: Pricing power, Midland water for sure. Midland Basin water, they definitely have pricing power. As the volumes decline, that's going to work to their advantage because for at least where they are, predominantly Howard County, there are just no other competitors in the area. There's very limited upstream-owned infrastructure. They're going to be able to display pricing power there even as volumes start to decline. On the New Mexico side, if they are willing to make the investments and get more processing and get more sour infrastructure in place, I think they will absolutely be able to exhibit some pricing power there, but it's really about who's first to market. They have got to get capacity online before other operators are able to do that. They just need to execute on that and do that. I think crude is going to be very challenged even with the assets they already have in place. It's so competitive on the Midland Basin side and even in New Mexico, it's going to be harder to exhibit any kind of pricing power there because there's crude infrastructure everywhere.

00:48:26] What's your outlook on further consolidation in the water midstream space today? It's been ongoing for some time now. Do you think the runway is still attractive, or have we reached a point where you have to consider organic growth?

MT [00:48:52]: There's been a lot of consolidation. There are definitely fewer M&A opportunities out there today than there were three or four years ago. What you're seeing right now is when those opportunities do come to market, there are a lot of people bidding for the same assets. What you're seeing a lot of now is a lot of buyers that are coming in are these long-term infrastructure PE shops. These are not the smaller PE shops that are seed funding USD 100m-200m for a midstream start-up. We're talking about the big guys that are buying mature infrastructure assets and are basically willing to underwrite to lower returns because they're basically looking at it as an annuity play. You're seeing a lot of those guys starting to come into the market now, and they're pricing things at a lot higher multiples than what strategic buyers like myself would probably price to.

There are fewer opportunities out there. The stuff that's out there that has good contracts is getting priced high. You're starting to see a lot of guys shifting back to focusing on greenfield development. Really honing in on the areas where there's really good remaining inventory, understanding the reservoir well and then trying to be the first to get greenfield infrastructure in place. I think the areas where we're going to see a lot of investment that is probably areas where the infrastructure is still heavily undersized is Delaware Basin, particularly sour production and then Haynesville, Haynesville, Haynesville. There's not nearly enough infrastructure built today to handle the production that's expected to come out of the Haynesville.

00:50:56] Looking at Delek's USD 180m-190m capital budget, if commodity prices were to pull back or producer activity were to soften materially, how much of that spend do you view as structurally committed vs flexible? Could the company pull back on that? Is the USD 180m-190m budget already committed and not necessarily flexible?

MT [00:51:33]: I think what probably matters is how much of that is serving existing dedications. If it's serving existing dedications, which most of it should be, and those particular operators have not indicated that they're pulling rigs or doing anything, which I don't expect that to happen in the market right now, then there's probably not a ton of flexibility there. I'd say that's, for the most part, going to be committed. Also, keep in mind, a lot of these projects that Delek is having to focus on in New Mexico, these are long-lead projects, meaning you're having to start 18-24 months out for an asset because you know it's going to take that long to get it online. Your forecasting is very different. You're having to think far enough ahead about what you're going to bring online and commit to it, but then there's probably some stuff in there that they've got budgeted for, for M&A stuff that might come up or some greenfield stuff that maybe it's bolt-on, but they don't necessarily need to do it. That's the type of stuff that's going to be more flexible, but that should be a smaller portion of that total capital budget.

00:52:53] Is there anything regarding Delek that you think would be important to understand or keep an eye on over the next 1-2 years?

MT [00:53:06]: I'd say, look, on the positive side, Delek is in a great position in the Delaware Basin. Their asset footprint in Lea County is right on top of where there's still a really great remaining inventory. A lot of it is sour, but there's really great inventory there. They just got to execute. Their contracts give them a really strong moat for that area. They've got a really strong competitive position there. I think in terms of where they're probably weakest is on the Midland Basin side, where their assets are, inventory, a lot of that's drilled up at this point. There's not a ton of growthway there. On the crude side, their margins are going to continue to be compressed just because it's an increasing competitive area. Everybody is fighting (inaudible 54.03) now for whatever remaining growth is there to get. Then on the water side, they've got a great asset that's consolidated, but not a lot of runway on growth that you're going to see on that asset in the future. When you do see those QoQ pops like they saw this past time, that's great, but I think it's going to be tough to make that sustainable.

CL [00:54:29]: I think that's about all my questions for today. I'm going to leave it there, but I just want to say thank you for joining me and sharing your insights on Delek.

MT [00:54:39]: Great. Thank you.

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