Welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode. During the Q&A session, if you'd like to ask a question, you may press star one on your phone. Today's call is being recorded. If you have any objections, you may disconnect at this time. I'll now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you, Ted. As usual, before we begin, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities Exchange Act of 1934, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release, as well as review our latest filings with the SEC for important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. Today, Steve, Kim, and David will take you through the details, but we believe 2023 is off to a good start. While in a company our size, there are always lots of moving parts. I think 2023 will be a solid year for KMI, and that with our capital expenditure program, we are positioning ourselves well for 2024 and beyond. At both the board and management level, we remain committed to transparency and to utilizing our strong cash flow to benefit our shareholders by maintaining a strong balance sheet, funding capital projects that produce returns well in excess of our cost of capital, paying a healthy and growing dividend, which by the way, in terms of yield, is one of the top 10 in the S&P 500, and repurchasing our shares on an opportunistic basis. In addition, through our investments in renewable natural gas, renewable diesel, and carbon capture and sequestration facilities, we are participating in the transition to cleaner energy. Let me conclude by reiterating our view, consistent with that of most energy experts worldwide, that fossil fuels will supply the great majority of the planet's energy needs for decades to come. For example, the recent IEA World Energy Outlook predicts that fossil fuels will supply 62% of the world's energy demand in 2050. Just this week, our Assistant Secretary of Energy stated that given the current state of events, and I quote, "The world absolutely needs new gas investment." End quote. While we expect that renewables will experience rapid growth over the coming years, the demand for energy as a whole will also increase substantially, thus driving the continued use of fossil fuels with natural gas playing an especially important role in the coming energy transition. In my judgment, this outlook deflates the argument of those investors who avoid our segment because they do not believe our assets will produce long-term value. With that, I'll turn it over to Steve. All right. Thanks, Rich. I'll make a few key points about our business, and then Kim and David will cover the substance and details of our performance, and then we'll take your questions. The overview is this: Our balance sheet is strong, our backlog of projects is up, and our largest business, natural gas, continues to show growing strength. A couple more details on each of those. We built our budget for this year with balance sheet capacity available to enable opportunistic share repurchases and incremental investment opportunities at attractive returns, and we have done both. Second, the backlog of projects are at attractive returns in aggregate, well above our cost of capital. At Investor Day every year, starting with the 2015 to 2017 period, we have been showing you on an EBITDA multiple basis how we perform in those investments relative to our original assumptions. We have performed very well. It's currently a challenging time from a supply chain standpoint. We expect to deliver the current slate of projects, even with a challenge here and there, at very attractive returns. Our current backlog is $3.7 billion, up $400 million quarter-to-quarter and at an aggregate EBITDA multiple of 3.5x. Third, on renewals, we showed at the beginning of the year how our base business renewals in the 2023 budget are showing more increases than decreases, especially in our natural gas business as the network tightens with increasing supply and demand. A strong balance sheet, a growing backlog, and good signs in our base business. A few other broad points about the macro backdrop underpinning this performance. First, as is becoming clearer as time goes on, and as Rich mentioned, hydrocarbon infrastructure is gonna be needed for a very long time to come in its current use. The world needs reliable and affordable energy to advance human development, and it needs natural gas transportation and storage assets to backstop renewables. Second, our assets are also well-positioned for the energy forms of the future. You can see that with the renewable liquids fuels and renewable feedstocks projects in our products and terminals businesses. Third, our existing natural gas transportation and storage network is growing more valuable as the grid tightens with increasing demand over time and increasing volatility. Compounding this effect is the difficulty of siting new infrastructure in many parts of the country. The value of the network was on display in the first quarter, where we had strong performance in our gas business in what was otherwise, except for the West, a mild and unremarkable winter. On the other hand, our network is well-positioned for expansion in those parts of the country where it is possible to build new infrastructure, the Gulf Coast, primarily. Our gas transportation and storage network is well-positioned in Texas and Louisiana, where over 90% of natural gas demand growth is expected to take place. This point is well demonstrated by the growth in natural gas projects in our backlog. With that overview, I'll turn it over to Kim. Okay, thanks Steve. I'm gonna start with the natural gas business unit as usual. Here transport volumes increased by about 3% for the quarter versus the first quarter of 2022. That was driven by EPNG's Line 2000 return to service in mid-February. A 10% increase in deliveries to power plants as a result of colder weather in the Southwest, coal retirements, and low gas prices. The increases were offset by reduced LNG volume that was attributable to the Freeport outage, decreased exports to Mexico, and reduced HDDs in Texas, Midwest, and the East. Natural gas gathering volumes were up 18% in the quarter compared to the first quarter of 2022. That was driven by a 42% increase in Haynesville volumes and a 21% increase in Eagle Ford volumes. Sequentially, total gathering volumes were up 4%. In our products pipeline segment, refined product volumes were flat for the quarter versus the first quarter of 2022. That was roughly in line with EIA, although there's some variability in the components. Road fuels were down 3%, but we saw a 12% increase in jet fuel as international travel increased. Our crude and condensate volumes were down 5% in the quarter versus the first quarter of 2022, and that was driven by lower Double H volumes as a result of unfavorable locational basis differentials coming out of the back end. Sequentially, volumes were up 1%. In our terminals business segment, our liquids lease capacity remains high at 93%. Excluding tanks out of service for required inspections, approximately 96% of our capacity is leased. From a market perspective, there's been some nice improvements in our major liquids markets. In the New York Harbor, our Carteret terminal is effectively 98% leased and had the strongest Q1 throughput since Q1 of 2019. In the Houston Ship Channel, we're effectively 100% leased and rates have firmed up. The Jones Act market continues to strengthen. On the bulk side, overall volumes were up 3%, and that was due to increased volumes in petcoke, coal, steel, and grain. In the CO2 segment, prices were flat to down, depending on the commodity. On volumes, CO2 volumes were down about 3%. With respect to oil volume, during the quarter, we had an outage at Sacroc, which is our largest field and accounts for roughly two-thirds of our net production. The field was down completely for 10 days in late January, early February, and then it took another 7 days to ramp up to full production, which impacted both our oil and NGL volumes. It's hard to recreate what would have happened if we didn't have the outage, but our very rough estimate is that overall net oil production would have been up 6% or better comparing the first quarter of 2023 to the first quarter of 2022, as opposed to being down 2%. NGL volume would have been up 1% versus being down 22%. These volumes would have added roughly $16 million or more to our segment results. Despite this outage, we still expect overall net oil volumes to be on budget for the year. With that, I'll turn it over to Dave and Michael. Thank you, Kim. For the first quarter of 2023, we're declaring a dividend of $0.2825 per share, which is $1.13 per share annualized, up 2% from the 2022 dividend. I'll start with a few highlights. We ended the first quarter of 2023 with net debt to adjusted EBITDA of 4.1 times, which leaves us with a good amount of capacity under our leverage target of around 4.5 times. We ended the quarter with over $400 million of cash on hand and nothing drawn on our $4 billion revolver capacity. We also issued $1.5 billion of bonds during the quarter, which addresses the majority of our funding needs for the rest of the year at favorable rates. We repurchased 6.8 million shares at an average price of $16.62 per share. We entered into additional short-term interest rate locks. We have now eliminated short-term interest rate exposure on about half of our floating rate debt through 2023. That helps protect us from further interest rate pressure. The locks have an average rate slightly better than our budget. Our balance sheet and liquidity are strong. We continue to create value for our shareholders in multiple ways. For the full year, we're leaving our 2023 budget guidance in place. It's still early in the year. A lot could change. We are facing pressure from commodity prices as prices both realized to date as well as in the forward curves are below our budgeted prices. Our forecast shows that pressure being substantially offset by better than expected operational performance, particularly in our natural gas and terminals business units. Before going on to the quarterly performance, you will notice that our financial disclosure has been updated. We believe this updated disclosure is more aligned with recent SEC guidance, particularly related to non-GAAP disclosure. On to the quarterly performance. We generated revenue of $3.9 billion, which is down $405 million from the first quarter of 2022. Our cost of sales was down $679 million to $1.2 billion. As expected, interest expense was up versus 2022. We generated net income of $679 million, up 2% from the first quarter of last year. Adjusted earnings, which excludes certain items, was $675 million, down 8% compared to the first quarter of 2022. On our business unit per-performance, our business segments were up 3% from the first quarter of 2022 in total, and our natural gas and terminal segments were up, and our products and CO₂ segments were down. Our natural gas segment was up with the largest drivers coming from greater sales margin on our Texas intrastate system and favorable rates on our recontracting at Midcontinent Express Pipeline. Our product pipeline segment was down mostly due to favorable first quarter 2022 commodity prices, which benefited our transmix businesses. Our terminal segment was up mainly due to rate escalations and stronger volumes in our bulk terminals businesses. Our CO2 segment was down due to lower NGL prices and volume, lower oil volume and higher pipeline integrity costs. Our G&A and interest expenses were higher versus the first quarter of last year. Additionally, in the first quarter, we had sustaining capital higher versus last year. We budgeted to have higher sustaining capital for 2023 versus 2022, and currently we're forecasting sustaining capital to be only slightly higher than budget for the full year. We also had, but also some of the quarter over last year quarter variance is due to some spend being accelerated into the first quarter. Our adjusted EBITDA was $1.996 billion for the quarter, up 1% from last year. Our DCF was $1.374 billion, down 6% from last year. Our DCF per share was $0.61, down 5% from last year. Moving on to our balance sheet, we ended the first quarter with $30.9 billion of net debt. Our 4.1 times ratio is the same as it was at year-end 2022. Our net debt decreased $52 million over the quarter. Here's a high-level reconciliation of that change. We generated $1.333 billion of cash flow from operations. We paid out $625 million approximately in dividends. We spent approximately $550 million in total capital, that includes both growth and sustaining capital, as well as contributions to our joint ventures. We spent $113 million on stock repurchases. That gets you close to the $52 million change for net debt. Finally, I'd like to remind our research analysts that we provide a quarterly breakdown of our annual budget on several metrics, EPS, EBITDA, and DCF. We do that since our expected yearly results are not evenly distributed. The main driver of that is our seasonality in our natural gas pipelines business, which typically generate greater margin on our first and fourth quarters due to strong winter demand resulting in higher rates and capacity utilization. Additionally, we usually have greater expenses in the second quarter due to estimated tax payments. For example, we disclosed that our budgeted DCF for the first quarter was approximately $1.4 billion, while our budgeted DCF for the second quarter was approximately $1.0 billion, reflecting that expected seasonality. Our actual DCF for the first quarter was $1.374 billion, a little lower than our budget, partially due to that accelerated capital sustaining capital spending. At this point, there are a number of analysts' estimates that appear to be out of line with this quarterly guidance. We encourage you to revisit that guidance as necessary. With that, I'll turn it back to Steve. Okay. Ted, we'll open it up to questions now. I'll just point out that, in addition to the people you've heard from so far, we've got a good portion of our management team around the table here, and we'll try to make sure you get an opportunity to hear from them on the questions you have about their businesses. Ted, let's open it up. All right. The phone lines are now open for questions. If you would like to ask a question over the phone, please press star one and record your name. If you'd like to withdraw your question, press star two. First question in the queue is from Brian Reynolds with UBS. Your line is open. Hi. Good afternoon, everyone. Maybe to start off on the EBITDA guidance. You talked about the base nat gas business perhaps outperforming slightly during the quarter, which is offset by, you know, the crude and nat gas deck and slightly lower product and terminals volume. I guess perhaps on a forward-looking basis relative to the original guide in January, could you provide some puts and takes on a go-forward basis as the base nat gas business perhaps outperforms while the commodity deck and then products volumes relative to the January guide and PHP delay, you know, partially offset? Thanks. Yeah. I think the bottom line summary is commodity prices are pressuring our business in the CO₂ business and a little bit in our natural gas business. Those are being largely offset with some of the items that you talked about, largely offset so far for the year. That business operational performance outperformance is offsetting that commodity price weakness. A lot of that's coming in our natural gas business, particularly in intrastates, and in our PALs and higher capacity sales values across our system in the natural gas business. We're also seeing higher terminals rate escalations than what we had budgeted. Great. Thanks. Maybe as a follow-up on growth CapEx, PHP's delayed a few months, and then you have the TGP East 300 project and the Tennessee Valley Authority projects coming into the backlog, apparently. You know, is there any upward pressure on CapEx this year, or could some of that get pushed into next? Thanks. Yeah. Look, there's some upward pressure on CapEx, but it's not, I don't think, material to the overall investments that we're making this year. Really what we're seeing is there's been a slight uptick in our capital expenditures, discretionary capital expenditures for the year, but that's largely due to new opportunities that have emerged over the course of the year. Look, we've been managing this since we started seeing inflation crop up over the course of 2022. We continue to do that and continue to examine our assumptions. When we sanction new projects, we're always making sure that our cost and schedule estimates are up to date. We're monitoring on a routine basis the lead times for various key components, et cetera. Overall, like I said in my remarks, I think we're expecting to do very well on the capital that we're putting to work. Great. Appreciate it. I'll leave it there. Have a great rest of your evening. Next question in the queue is from Jeremy Tonet with J.P. Morgan. Your line is open. Hi. Good afternoon. Good afternoon. Just wanted to follow up on the last point, I guess, as it relates to operational performance in the quarter versus budget. Noted that Texas Interstate doing better than expected. Is that a function of just long-term contract renewals at better than expected rates, or was that kind of marketing opportunities that are spread-based? Just trying to get a bit more color on the drivers there and the durability of those trends. I mean, it's really kind of across the board. It's on contract renewals, it's on short-term business that we're doing, and it's on rates that we're getting for new business as well. Cecil, do you have any other comments there? Yeah. I mean, I really... And also, improved storage value, you know, a big piece. Got it. That's very helpful there. Just kind of shifting to the Permian as a whole. Natural gas egress, we've seen volatility in Waha prices. With PHP being pushed off a little bit here, would imagine that would persist across the year. Just wondering your thoughts, I guess, for egress and when the next pipe out of the Permian could be needed and, you know, if how Kinder could participate in that type of project. Just wondering updated Permian natural gas egress thoughts on your side. Yeah. Well, of course you're right. Waha has faced some pressure as a result, and there's been a combination of just continued growth in production. There's been some maintenance, which used to be sort of back page Gas Daily kind of thing, but now it's sort of front page of mainstream media. There's that. There's the growth in the underlying business, we clearly need additional expansion capability out of there. PHP provides that on a pretty quick basis. We are seeing a small delay, but that was fast capacity addition that we're doing largely with compression and just a tiny bit of pipe out there. In terms of the longer term project egress, there are some on the boards right now. We continue to evaluate a long-haul pipe expansion, but we're not making any real commitments or updates on that. We'll continue to talk with customers. We believe it will be needed, but probably in Cecil. 26, 27. ... 26, 27 timeframe. We'll continue to work on it. 2026, 2027 in service, or when a new pipe would start construction? in service. That's very helpful. Thank you. The next question in the queue is from Colton Bean with Tudor, Pickering Holt. Your line is open. Good afternoon. Maybe just sticking on PHP. You know, it looks like the 1 to 2 months delay there versus initial expectations November first. Is first any detail on which components are driving the shift? Then are those now in hand, or do we still need to see some supply chain improvement to hit the December in-service? I don't know about in hand. This is our provider of the compression, and they have upstream providers of certain really it's electrical equipment. They have that identified. They're getting it, but it's been delayed, and so that's why we reflected a delay. We're still gonna get this thing done. It's just supply chain is still a little bit tangled. That's what we're seeing there. Okay. Based on everything you're seeing today, it still seems like, you know, sometime before year-end? Yes. Yes. Yes. Great. Then David, you mentioned locking in roughly half of the floating rate exposure through year-end 2023. I guess, can you comment on where that stands for 2024? More generally, you know, do you have interest in locking in rates for next year, or content to see how the market plays out for the time being? Yeah, it's a good question. It is something we've taken a look at. We haven't locked anything in for next year yet. When we first started locking in interest rates, for to address some of our floating rate exposure, it was when interest rates were really, really low, so there was very little downside in doing it. We started doing it this year because there was some volatility that we forecasted for the year, and so we wanted to take some of the potential downside pressure off the table. Still too early for us to weigh in on what that environment looks like next year, but we'll continue to keep an eye on it. The swaps that expire? We do, yeah, we do have some. That's a good point, Kim. Kim reminded me that we do have some of the swaps about, I think it's $1.2 billion of our swaps in our portfolio mature by the end of the year this year. That's also a component that we're gonna take into account when we're thinking about locking in future swaps. The next question in the queue is from Michael Blum with Wells Fargo. Your line is open. Thanks. Hey, everyone. Wanted to ask about D3 RIN prices. They've come down quite a bit recently. I wonder if you can just remind us how this impacts the economics of your RNG projects. Yeah. Anthony Ashley. Yeah, Michael, hi. Yeah, what we've seen, I think, is a bit of a short-term phenomenon with. It kind of resulted out of the EPA proposal that came out last November. They came out with proposed RVO targets, which were, I think clearly the market realizes were too low, threw the market into excess supply. The current prices today, there's really no liquidity in, so I don't think there's necessarily any basis in those numbers. You know, I think there's substantial evidence for the EPA when it comes out with its final ruling in June to increase those targets, we fully expect RIN prices to recover in the second half of the year. Just maybe two other points, Anthony. We're not a forced seller of D3 RINs, so we're not forced for funding or financing or other reasons to come out into this market at this point. The other point is we do this routinely, but we look to stress test our project returns to make sure they're still good returns under different RINs pricing scenarios, and the projects and the investments that we've made in this sector still look good. Okay. Thanks for all that. My second question, I wanted to ask about the balance sheet. Your leverage is just 4.1. Your budget for the year is 4.0. Your long-term target is 4.5. Any thoughts to reduce that target over time, or should we expect that leverage will go back to that 4.5 times level over time? If it does, what would get you there? Thanks. Yeah, it's a good question, Michael. No, we don't have an anticipation of changing our long-term leverage target of around 4.5 times. We have been operating below it. We think that's prudent. It can give us some cushion should we have any headwinds or should we see favorable opportunities out there to take advantage of. We could utilize some of that capacity to take advantage of those opportunities. I think we would just have to wait and see what those look like. I don't think we have any particular ones on our table right now. I think we would say that we'd be disciplined with the utilization of that capacity because we do like having some of that cushion available to us. Thank you. The next question in the queue is from Neal Dingmann with Truist Securities. Your line is open. Afternoon, guys. My question is natural gas storage. I'm just wondering how you all view the natural gas storage opportunities, you know, given out there. Obviously, the time spread reflects pretty heavy contango right now. I'm just wondering maybe how much of a spread could you possibly capture? I'm also curious if there's a lot of growth opportunities around that. Yeah. Neal, we've flipped from a backward ending curve to a contango curve. We see the supply and demand fundamentals moving in a positive direction. When you just take a step back and look at storage, we're seeing volatility across the network. I think the value in terms of what we can get to is new build, right? The new build mark. We've been, you know, renewing storage at the $3 mark as of late and probably north of that. I think, you know, as we move forward, we continue to see longer term renewals as well as higher priced renewals. Got it. Okay. Then just lastly, just on RNG, just wondering again, maybe you could just address that market overall. It seems that haven't heard as much recently from you all or just on others, other opportunities that you might be seeing just on the horizon there. Anthony. Yeah. I think where we are today is, where our focus is on building out of the projects that we have in place that we effectively acquired with the 3 acquisitions we've done over the last couple years, has been, I think on an M&A front, you know, become a little bit more of a frothy market for us. Our focus has been building out the projects we have and future organic growth there. Very good. Thank you. The next question is from Jean Ann Salisbury with Bernstein. Your line is open. Hi. Good afternoon. Can you talk about the current backlog, with the better multiple expectation at 3.5, obviously, than kind of your historical average? Does that reflect a raising of the bar generally, or is it specific to a couple of brownfield projects, big ticket items in the current backlog, and I shouldn't read into it too much for the long term? Yeah. It's not really a raising of the bar. We've had a hurdle rate that we've talked about. Before of about 15%, that turns out to be kind of a starting point. If there's a project with long-term contracts, secure cash flows, and very consistent cash flows, we flex off of that, which we do on bigger projects. That gets you to why you're seeing a difference in the multiple. The bigger long-haul projects and the bigger investments, they tend to be done in an environment where there are others who are competing for that, and we end up with a good return, but a bit of a higher multiple of EBITDA. Think GCX, PHP, think of Elba as an example, you know, over this period of time that we're talking about where we've had our hurdle rate in place. There have been more of those in the mix historically when we've been kind of showing you guys 6x EBITDA multiples on our projects when we do our annual update at the investor conference. Now a lot of these projects are high return build offs of the existing network, at very attractive returns. The multiple ends up being a lot more attractive. The EBITDA multiple is a lot lower as a result. Not a function of hurdle rate, more a function of the composition of long haul and short haul call it. Great. That makes sense. After Winter Storm Uri, as you guys kind of talked about, there should have been kind of willingness to pay more for gas pipelines and storage in Texas as a form of insurance, and it looks like that's been flowing through. I guess my question is, there's been some talk about this Texas Energy Insurance Program, this thing about building out all of these insurance gas power plants for spare capacity. Would you view that as a positive or a negative for Kinder Morgan if it does go through? In a way, I suppose it's sort of competing for insurance with your storage and pipeline capacity. Not really competing with it. It would be a customer for it. Look, we'll break it into two here. One is whether or not it's good public policy, and I'll refrain from commenting on that. The other is if they build new gas-fired capacity in the state of Texas to improve reliability on the electric grid, that's a good thing for gas companies in Texas. You could have a long debate, and there is a long debate happening in Austin on whether you ought to just simply let the people who already built those things and have been building them at least along our footprint, to continue to build them as opposed to having the state build them or incent their building, I guess. Okay. Thank you. That's all for me. Next question is from Spiro Dounis with Citi. Your line is open. Thanks, operator. Afternoon, guys. Kim, first one's for you. I think you had mentioned lower natural gas prices as a positive factor in attracting back some demand from power and industrial customers. Curious if you think we've maybe seen a lot of that demand elasticity, you know, sort of snap back and play out at this point, or do you think there's a lot of latent capacity in the system that maybe hasn't reacted to lower prices yet? In terms of the power demand? Well, I'd say, you know, the power demand we saw in the first quarter was up 10% versus the first quarter of 2022. We saw nice increases in power demand. We didn't have a winter in, you know, the center of the country all the way east, really. Had we had more HDDs during the winter, I think, you know, that power demand could have been higher, than what we saw, and therefore the gas that we moved to those power plants would have been higher. Got it. Okay. That's helpful. Second question also on nat gas prices. If I could maybe just curious to get your all's thinking on the trajectory of nat gas prices from here. I guess as we look out, you know, beyond 2024 into 2025, we see a lot of that LNG capacity coming, which should be supportive. I think between now and then, there is an expectation here that that supply could push prices down further. Just given you guys are close to your customers, just curious kind of what you're hearing and maybe how you'd expect producers to react if we do see prices fall maybe below $2. Sure. With respect to the associated gas, obviously don't expect much impact there. You know, we've had a lot of discussions with our producers in some of the dry gas basins. The break-evens there are pretty low, is what I would say. The, you know, there's always the potential that it could go lower, but we think again, as you said, as the LNG demand comes on in 2024 and 2025, that those prices improve. As we've talked to our producers, you know, in the Haynesville and the Eagle Ford, you know, we've seen some pullback from the small and medium-sized. Most of the larger producers are continuing to produce. You know, as we look at our outlook on our gathering volumes for the year, you know, we're within 2% of our budget, the 2% off of our budget. Part of the reason that we're off of our budget has nothing to do with, you know, prices. It really has to do with the delay in a project. That's kinda what we're seeing. Got it. Appreciate all that color. That's all I had. Thanks, guys. The next question is from Sunil Sibal with Seaport Global Securities. Your line is open. Yes. Hi, good afternoon, everybody. I just wanted to flush the natural gas long-haul pipeline capacity in Permian a little bit. Seems like, you know, when you look at the volatility in the Waha prices, you know, it seems to have gone up over the last few months, you know, despite the fact that EPNG, you know, outage has been restored. I was just curious, you know, if you could talk a little bit about, you know, the nature of your conversations with the customers with regard to, you know, building new capacity there. What are the major kind of sticking points before a big, you know, project could go ahead? Yeah, I mean, look, when we look at Waha, there's clearly, you know, as you look out long term with all the LNG demand coming on, there is gonna be basis differential that needs to be solved for. You know, really what this is gonna take is commercialization. As you know, you know, we've been talking with customers about, you know, a third pipe out of the basin. You know, where that gets pointed ultimately depends on the market need and which LNG facility gets FID next. We have been having discussions on both sides with the supply side and the market side trying to bridge the gap. I think really ultimately it comes down to timing, from the market side as well as commercializing an appropriate rate of return, from our perspective. Got it. Thanks for that. At this time, I'm showing no further questions. Okay. Well, thank you very much for joining us today, and have a good evening. This concludes today's call. Thank you for your participation. You may disconnect at this time.