Good afternoon and welcome to the quarterly earnings conference call. At this time, I would like to inform all participants that today's call is being recorded. If you have any objections, you may disconnect at this time. You have been placed on a listen-only mode until the question and answer session of today's call. If you would like to ask a question at that time, please press star one on your phone. Please make sure your phone is unmuted, and record your name and company name clearly when prompted. I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you, sir. You may begin. Okay. Thank you Michelle. Before we begin, I'd like to remind you, as I always do, that KMI's earnings release today and this call includes 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 disclosures 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. Let me begin by today, we formally announced our dividend increase for 2022, taking the annual payout to $1.11. That's the fifth consecutive annual increase. Also, as Steve Kean and the team will tell you, the year is off to a good start. Now I wanna talk about broader issues that impact all of us. Since our last call in January, seismic events have occurred. The Russian invasion of Ukraine has shaken the world order as we know it with a dramatic impact on the economy of Europe and indeed the entire world. Predicting how this whole tragic situation will be finally resolved is far beyond my capabilities, but I'm pretty certain the impact on the energy segment of the economy will be significant, at least over the next several years. This crisis has demonstrated the continued dependence of the world on fossil fuels, especially natural gas, and the inability to develop a satisfactory substitute in the short to intermediate term. This situation is illustrated by the frantic efforts of Europe to wean itself from its overwhelming reliance on Russian natural gas. Beyond that, we are shown once again how tight the world market is for oil, natural gas, NGLs, and even coal as we look at the dramatic escalation in prices since the war began in late February. What does this mean for the energy space in America? In my judgment, the crisis plays to our strengths. The U.S. is a reliable supplier with the ability to grow its production modestly in the near term and more robustly in the intermediate term. We operate under a transparent legal system, and we have technical expertise from the wellhead to the burner tip that is unmatched anywhere in the world. For all these reasons, the United States will be a major part of the solution to adequately supply the world with oil and natural gas it needs to surmount the present problem. In particular, the U.S. will be a major supplier of additional LNG to Europe to replace, at least in part, Russian gas. I anticipate that all of our present LNG export facilities will be running at capacity for the foreseeable future, and the contracts necessary to support the construction of new facilities in the next few years will be more attainable than they've been in the past. By way of caution, I'm still concerned that our federal government will not properly expedite the permitting of these new facilities. I'm reasonably hopeful that at some point, this administration will recognize the importance of playing its energy card to support its allies and sanction its adversaries. The impact of these developments will benefit the midstream energy segment and Kinder Morgan specifically in both the short term and the long term. At Kinder Morgan, we move about 40% of all the natural gas in America and about 50% of the gas going to LNG export terminals. As volumes increase, throughput will increase as will the need for selective expansions and extensions of the network. In short, it's a good time to be long natural gas infrastructure. Steve? All right. Thanks Rich. After wrapping up a record year financially in 2021, we're off to a strong start in 2022, with strong performance in our base business and attractive opportunities to add growth. We're keeping our balance sheet strong, exceeded our plan in the first quarter, and even though it's early in the year, we are projecting to be above plan for the full year. In addition to commodity price tailwinds, we experienced very strong commercial performance in our gas business with continued improvement in our contract renewals, especially on our flexible gas storage services, good performance during the winter, and new emerging project opportunities in our Bakken, Haynesville, and Altamont assets, and increasing interest in new Permian transportation capacity. On the Permian, we are working on the commercialization and development of compression expansions on our PHP and GCX pipelines. While we will need to do a small amount of looping, most of the expansion can be accomplished with additional horsepower. Compression expansions are low risk from a siting and permitting perspective, and they are very capital efficient, though they do come with a higher fuel rate for the customer. Most importantly, in today's environment, compression expansions allow for speed to market. Once we have contracts and make FID, we believe we can get to in-service in about 18 months. We believe the market will need that capacity in that time frame and see one or both of these expansions as the near-term solution pushing out our potential greenfield third pipeline further in time. Combined, the two expansions can add 1.2 BCF per day of capacity out of the Permian. Finally, for gas, our Stagecoach storage asset, which we acquired in 2021, helped us with our strong winter performance and continues to perform above our acquisition model. Our CO₂ business was aided by commodity prices and also operational outperformance versus our plan. We continue to advance our three renewable gas projects, which we picked up in the Kinetrex acquisition last year, and we are advancing additional opportunities in our energy transition ventures group. Our products pipelines were modestly above plan for the quarter, and while terminals missed plan by a bit, we started to see good recovery in our Jones Act charter rates and continued strong performance in our bulk terminals business. For the balance of the year, commodity prices continue as a tailwind, and we have locked in enough dollar movement of WTI. We expect continued strength in our base business, but we also expect to experience some negative impact from cost pressures due both to additional maintenance and integrity work that we added to the plan for this year above plan for the year. In summary, we're doing very well. With that, I'll turn it over to Kim. Okay. Thanks Steve. I'll go to the segments starting with natural gas. Our transport volumes there were up decatherms per day versus the first quarter of 2021 by increased LNG deliveries, generally colder weather, partially offset by the continued decline in Rockies production and a pipeline outage on EPNG. Deliveries to LNG facilities off of our pipes averaged approximately 6.2 million dekatherms per day, up to 32% 2021. Our market share, as Rich mentioned, remains around 50%. Exports when compared to Q1 of 2021 as a result of third-party pipeline capacity added to the market. Overall deliveries to power plants were up 5%, and we believe that natural gas power demand is becoming more inelastic relative to coal. Deliveries to LDCs and industrials also increased. The overall demand for natural gas is very strong. Both our internal and Wood Mac numbers project between 3 and 4 BCF of demand growth for 2022. It [worries] ResCom, industrial, power, exports to Mexico, and LNG exports. Our natural gas gathering volumes were up 12% in the quarter compared to the first quarter of 2021. Sequentially, volumes were down 6% with a big increase in Haynesville volumes, which were up 14%, more than offset by lower Eagle Ford volumes, which were impacted by in the natural gas segment to increase by 10% for the full year number. In our products pipeline segment, refined product volumes were up 7% for the quarter compared to the pre-pandemic levels using Q1 of 2019 as a reference point. Road fuels were down about 0.5%, so essentially flat, while jet was down 18%. We did see a decrease in the monthly growth rate as we went through the quarter, so higher prices may be starting to impact demand. Crude and condensate volumes were down 4% in the quarter versus the first quarter of 2021. Sequential volumes were flat with a reduction in the Eagle Ford offset by excluding tanks out of service or required inspection. Utilization is our rack business, which serves consumer domestic demand, was up nicely in the first quarter. Our hub facilities, which are driven more by refinery runs, international trade, and blending. We're seeing some green shoots in our marine tanker business with all 16 vessels currently sailing under firm contracts, and day rates are still improving, though still lower relative to expiring contracts. On the bulk side, overall volumes increased by 19% driven by petcoke and coal, which more than offset lower steel and oil volume. In our CO₂ segment, crude volumes were essentially flat compared to Q1 of 2021, and NGL volumes were up 7%. CO₂ volumes were down 9%, but that was due to the expiration of a carried interest following payout on a project in 2021. On price, we saw very nice increases in all of our primary commodities. Overall, we've had a very nice start to the year. For the first quarter, we exceeded our DCF plan by 4%. We estimate that roughly half of that outperformance was due to price, and specifically quantify the outperformance because one, it is relatively early in the year, and two, there are a lot of moving pieces, commodity prices, gathering volume, volumes, inflation, regulatory demands, and interest rates to name a few. We expect the upsides to outweigh the downsides. With that, I'll turn it to David Michels. Thank you Kim. For the first quarter of 2022, we're declaring a dividend of $0.2775 per share, which as Rich mentioned, is $1.11 annualized and 3% up from our 2021 dividend. For the quarter, we generated revenues of $4.3 billion, which is down $918 million from the first quarter of last year. However, when you exclude the large non-recurring contribution from Winter Storm Uri from last year, our revenue would have been higher this quarter versus last year. Our net income was $667 million down from the first quarter of 2021. Excluding the contribution from Winter Storm Uri last year, our net income during the first quarter of 2021 would have been $569 million. Relative to that recurring amount, we generated $98 million or 17% higher net income this quarter versus last year. Our DCF performance was strong. Natural gas segment was down $797 million. Again, the winter storm contribution from last year, which was over $950 million in the first quarter of 2021, led to the majority of that decline this quarter. Otherwise, we had nice outperformance in our natural gas segment, driven by contributions from our Stagecoach acquisition, Tennessee Gas Pipeline contributions, our Texas intrastates, as well as greater volume on KinderHawk. The Products segment was up $36 million, driven by increased refined product volumes and favorable price impacts, partially offset by higher integrity costs. Our Terminals business up $11 million versus Q1 of 2021, with greater contributions from our bulk terminals, driven by higher petcoke and coal volumes, as well as growth in our liquids terminals business due to expansion project contributions and an unfavorable impact from Winter Storm Uri during 2021. Those were partially offset in the Terminals segment by lower contributions from our New York Harbor terminals and our Jones Act tanker business. Our CO₂ segment was down $83 million, and more than all of that decline is explained by the segment's contribution from Winter Storm Uri during 2021. Other than that, the CO₂ segment is up nicely year over year, mainly driven by commodity prices. Total DCF generated in the quarter was $1.455 billion or $0.64 per share. That's down from last year, but again, excluding the non-recurring contributions from Winter Storm Uri, our DCF would be up $203 million or 16% higher compared to the first quarter of 2021. Moving on to the balance sheet, we ended the quarter with $31.4 billion of net debt, with a net debt to Adjusted EBITDA ratio of 4.4 times. That's up from 3.9 times at year-end 2021. But excluding the non-recurring EBITDA contributions from Uri, the year-end ratio would have been 4.6 times. We ended the quarter favorable to our year-end recurring metric. The net debt during the quarter increased $191 million, and here's a reconciliation of that change. We generated $1.455 billion of DCF. We paid out $600 million of dividends. We contributed $300 million to our joint ventures and to growth capital investments. We had $250 million of increased restricted deposits, which is mostly due to cash posted for margin related to our hedging activity. We had a $500 million working capital use, which is not uncommon in the first quarter when we have higher interest expense payments, property tax bonus payments, and we also had a rate case reserve refund paid. That explains the majority of the $191 million for the quarter. With that, I'll turn it back to Steve. Okay. Thanks David. Michelle, if you'd come back on and open it up for questions. I'll just point out we've got our entire senior management team around the table here, so we'll be passing the mic if you have questions about our different segments and their performance and outlook, etc. Michelle, open it up, please. Thank you sir. At this time, if you have any questions or comments, you may press star one. Please unmute your phones and state your first and last name and company name when prompted. Our first caller is Jean Ann Salisbury with Bernstein. You may go ahead. Hey. I just wanted to ask about the potential compression expansions. How are customers comparing the compression expansion option versus a new build? Are the rates similar? Obviously, you mentioned that the timeline to market will cost us higher. Just wanted to understand which was kind of more attractive to customers. Very good. Tom Martin, President of our gas group. Yeah. I mean, can't get too specific about overall rates because it's competitive. Set by the fixed fee that's associated with it. I think the key is speed to market, and that's the message that we're hearing from our customers is that getting this in service in 2023 will really help alleviate a containment issue that we're really starting to see now and certainly expect to get much worse as we get into 2023. Not ready to call this a win yet. Clearly, we've got a lot of work to do, but we're getting some good feedback. Great. That's helpful. I guess on that topic, is 18 months to add compression and some looping kind of longer than a similar project in the past? Is this due to supply chain issues going on, or am I just, like, too demanding? Yeah, I mean, it may be somewhat longer, but you know, we've made some mitigating steps. We've taken some mitigating steps to help make that better than it otherwise could have been. I think in these times that's probably indicative if not longer. Okay. Just one more follow-up on this if I may. Are you seeing any movement from kind of the people that have not traditionally signed up for long-term contracts, like the privates to sign up this time given more constraints on flaring and everything? Or do you think it's gonna likely be the same mix of customers as in the past? Again, hard to speculate specifically on customers, but I think I would say it's a broader set of customers in general than what we may have seen on the greenfield projects. Speaking, I think really to the point you're making is that there's a broader set of customer interest this time. Great. That's all for me. That's super helpful. Thank you. Thank you. Our next caller is Colton Bean with Tudor, Pickering, Holt & Co. Sir, you may go ahead. Good afternoon. You all mentioned seeing higher costs in the release. Can you just elaborate on where you're seeing those costs hit the system, you know, whether that's materials, labor or other areas? There are two categories of higher costs here. One is that we've added some incremental integrity and maintenance work to the plan. That's not an inflation thing. That's just a scope of work thing. It's not a ongoing or recurring, but we're doing some work there that we'll be doing this year and probably next year. That's one category. The second thing is we haven't experienced a great deal of inflation to date. We experience as normal when commodity prices are up. You see it in the oil field, right? Commodity prices are up. The revenues are up to go with it. We're seeing some there. The other places where we're seeing inflation, we've projected a little inflation, but the places where we've actually experienced it are obviously fuel for our trucks, okay? For our other equipment. Fuel prices are up. Those prices are up. Related hydrocarbons or composites like lubricants is also up. Some materials, you know, steel costs for certain equipment has come up. Even though raw steel has come down a little bit, it's been down then up a little. It's some materials, equipment, lubricants, fuel. Great. Appreciate that. Rich mentioned the need for incremental U.S. LNG. Are there any optimization opportunities available to you all at Elba Island or alternatively, you know, if market interest has increased, could that be a potential divestiture candidate? The current project is fully utilized by our customer. There certainly is an opportunity to do an expansion there, small scale expansion. We had those discussions a couple years ago. Obviously with what is happening now, we're dusting that off again. Again, very early days to say whether there's real potential there. You know, overall the market opportunity you know suggests there may be something worth looking at. Colton, the thing I'd add to that is just that you know, a lot of the way we're participating in this LNG growth opportunity, both what has come to pass already and what we believe is still to come is off of our network. We can participate in that market and the growth opportunity by serving them and serving them well with our pipeline infrastructure and our storage assets along our network. Particularly with a lot of that growth coming in Texas and Louisiana, where our footprint is especially robust. You know, Elba is something we will evaluate, as Tom said, and we'll work with our customer on that. Really, a big play for us in the trend here is to be able to bolster what we do from a transportation and storage service provider standpoint. Got it. That's helpful. Appreciate the time. Thank you. Our next caller is Jeremy Tonet with J.P. Morgan. Sir, you may go ahead. Hi good afternoon. Afternoon. Just wanted to see with the compression expansions, if you are able to provide any thoughts with regard to capital outlay there for us to kind of frame it. You talk about being more capital efficient than a greenfield. At the same time as it relates to the new greenfield, does this really change, I guess, the pace of how you're exploring those? You know, the pace of that project, given how it's gonna take longer to build a pipeline today than it did in the past. Presumably there's gonna be need for incremental pipe beyond these expansions pretty quickly, at which point the Permian PHP could service that need. Yeah. Yeah. Again, I don't think we wanna get into capital discussions again in a competitive environment on the expansion project. I think to your second point. Yeah, I think you're exactly right. The market will fill up relatively quickly. You know, we're estimating a greenfield pipe will now be needed sometime in 2026 after all the expansions are done to fill the immediate need. You know, with that and given the timeline on doing greenfield type projects, I mean, that would lend itself towards and that might be sometime early next year for that kind of a project. Got it. That's helpful there. Just wanted to kind of pivot towards you discussed this GHG collaboration study with other partners in midstream here. Just wondering if you could expand a bit about that. I guess the objectives behind that, and I guess what were some of the drivers to moving forward with that project? Yeah, I mean, I think holistically, you know, international LNG markets are driving the bus on getting RSG and lower methane intensity type volumes. You know, really what this initial effort is is a pilot program to help identify methane intensity on specific assets at specific locations with hope that will broaden and ultimately support, you know, a certification process that will help earmark lower methane intense gas going to international markets. Jeremy, I'd just add to that, you know, that we have seen a bit of an inflection this year. We've been talking about our low methane emissions intensity and marketing that as part of our service offerings, and we've been doing that for a while. We got a deal last year, and we got another couple of deals following that. We got a tariff filing on TGP. There's all of a sudden an enormous amount of interest in it. By our estimate, 5% of the natural gas produced in the U.S. today could qualify. If you take all their targets into account, you get up to a third. We think that this is gonna be a point of distinction in the future, and we're seeing evidence of that now. Just to add on real quick there. Do you see this as something that increases profit or is it cost of doing business? Or how do you think about- It's too early to say. I mean, I guess my thought is that the ancillary services that come out of responsibly sourced some of the certification process as we go forward. You know, I think right now it's more about identifying what we can do and what we can't do on a large scale in the near term and identifying ways to harness that for the market. Got it. That's helpful. Thank you. Thank you. Our next caller is Brian Reynolds with UBS. Sir you may go ahead. Good afternoon. Good afternoon everyone. Maybe to start off on capital allocation. You talked about EBITDA guidance of, you know, roughly $7.2 billion being favored to the upside versus the downside as you kind of sift through the global macro uncertainty. You know, curious, given the change in the global macro since the analyst day, have any assumptions changed around capital allocation and the buyback commentary from January? I guess in other words, you know, have CapEx needs been pulled forward with the GCX and PHP expansions or the potential if FID a new Permian pipe impacts Kinder's process around, you know, potential buybacks this year and next? Thanks. Yeah. There's been no change in the principles. You know, we are focused on making sure we keep the balance sheet strong and that we fund available capital projects that provide good NPV at well above our weighted average cost of capital. Returning value to shareholders with the dividend increase that we're talking about today as well as share repurchases. We do have some additional capacity given our performance. We have some additional CapEx in our forecast. We went up a little over $100 million from where we were in the budget, and we continue to look for those. We're, you know, into the year a good amount now, and I think we're still confident in saying that we will have the capacity, even with the opportunities coming forward. We'll still have additional capacity beyond that. David, anything you wanna add? No, I think you covered it. Okay. Yeah, that's super helpful. Maybe as a follow-up on the Ruby bankruptcy proceedings. Just kind of curious if you could talk about Kinder's position as, you know, it seems like there's conflicting views on, you know, either handing over the pipeline to the bond holders versus looking to repurpose the pipe for the long term for additional purposes and, you know, protecting things. Yeah. The overall message on Ruby is the same as it's been for a long time, which is that we are gonna make decisions here that are in the best interest of KMI shareholders. You know, we're hopeful that as we enter into this new process, that we're gonna be able to work out reasonable resolutions. We continue to operate the pipeline and believe that's what makes sense in the longer term. I think you just have to separate out rhetoric in the courtroom from reality here. We'll continue to work in a constructive way with our counterparties. Appreciate the color. Have a good day, everyone. Thank you. Our next caller is Chase Mulvehill with Bank of America. You may go ahead. Good afternoon. I guess first question, I just wanted to come back to, you know, the natural gas egress discussion around the Permian. I think many investors thought that you'd probably see an announcement alongside today's results for brownfield expansions of GCX and Permian Highway. It does obviously sound like it's moving along, but I don't know if you'd be willing to kind of provide maybe your thoughts around timing of when something could get officially sanctioned here. Then you said 18 months, kind of, you know, I guess to get in service when sanctioned. Are you ordering any long lead time items that could possibly, you know, move things up inside of 18 months? Last one is just opportunities to expand or do expansions outside of kind of 42-inch pipes. Do you see any opportunities there? I'll start and ask Tom to correct anything I get wrong here. We're not yet talking about timing. I think it's fair to say the market is very interested, and they see the wall coming in terms of capacity constraint. That has turned up the heat and turned up the volume on commercial discussions. Because of the timeframe that's required and the timeframe and the speed to market that we're able to offer, you know, we like our chances very much in this discussion. We're not gonna project a particular time. It didn't come alongside the announcement today because we get contracts before we go. We're working on that and we're working fast and hard on that. Not gonna talk about specific commitments, but I'll just say that obviously we've not been ignoring the supply chain challenges in the marketplace, and so we've made what we believe are appropriate mitigation steps to mitigate that risk for us. Okay. Any changes to when you think this bottleneck really festers in the Permian? You know, I think you said last earnings call you said year-end 2023. Is that kind of still the timeline of when you expect to see a bottleneck? I think sooner. Early, you know, later this year it begins, in early 2023. I mean, you can look at just the financial basis markets and it gives you some insight into 2023 appearing to be more towards a train wreck than it is today. So yeah, absolute need for egress as soon as we can out of that basin. Okay. Last one on repurposing assets. Could you talk about opportunities that you see to repurpose some of your underutilized assets? And then, you know, do you think this could be, you know, more near term opportunities or really just long-term opportunities you see to repurpose assets? You know, we don't. There's one project I can think of where we are actively looking at repurposing. It's not a huge part. I don't think you should count it as a huge part of our commercial activity right now, but it's something that we continue to evaluate. Michael Lapides with Goldman Sachs, you may go ahead. Hey, guys. Thank you for taking my question and congrats on a great quarter. We're a year and two months removed or so from Uri. Can you talk about what customers across the board, whether producers, utilities, power generators, whatever, are saying to you in terms of storage rates, meaning gas storage rates, the tenor of new gas storage contracts, and whether there's a physical need for expansion of gas storage capacity? A good question. Tom Martin. Yeah, no, a lot of discussions in that area. We have seen on contract renewals and a significant expansion on especially multi-cycle storage rates, especially in Texas, but I would say really across the whole footprint. I think there are opportunities to expand our storage facilities, especially in Texas. We're, you know, taking a hard look at doing that. You know, there seems to be a lot of interest in it. From both the power customers as well as local distribution customers, especially in the state of Texas. You know, I might add, too, our acquisition of Stagecoach was quite timely, as well, kind of right in the middle of this whole trend. As Steve said earlier, you know, we're performing well over our acquisition model assumption on that asset, and especially as we integrate that with our Tennessee asset as well. Got it. That's super helpful. Just curious, when you get and I know it's gonna vary by site obviously. When you get a customer or a series of customers interested in having you expand your existing gas storage facility, how should we think about just the process and the timeline to actually physically be able to do so? Yeah, I mean, it depends on what kind of an expansion we're talking about. If it's adding withdrawal capability or compression to add injection flexibility, you know, that's probably, you know, a 2-year timeline. Maybe slightly longer if you're talking about leaching additional caverns. Again, it depends if it's a brownfields type opportunity or a greenfield opportunity. I think that's generally, I would say, the timeline I would think about as you talk about expansion opportunities. Got it. Then one last one, hate to do back-to-back here, but different topic. Just curious how you're thinking about growth in the Haynesville from here, after a pretty solid start to the year, kind of what you think the trajectory is and whether you think Haynesville takeaway towards the Gulf Coast starts to get tight and whether you guys play a role in that. Yeah. Lynn, we've certainly seen tremendous growth, you know, year-over-year, quarter-over-quarter, in our gathering assets. I mean, about 300,000 a day, quarter-over-over. We're forecasting upwards of half a BCF a day, year-over-year, full year forecast 2022 versus 2021. Yeah, you're absolutely right. I mean, I think as that growth accelerates not only on our asset but other assets in the basin. Critical, I think there are some expansion projects that are probably more economical than an incremental greenfield. Those to fill, and there will be a need for incremental greenfield expansions out of that area as well, especially pointed towards the Gulf Coast for LNG exports. You know, we certainly are looking at that. Don't have anything that we're anywhere close to talking more about today, but certainly see that as a potential opportunity. Got it. Thank you, guys. Much appreciated. Thank you. Keith Stanley with Wolfe Research. You may go ahead. Hi. Thank you. I had two quick follow-ups. First, Steve, you talked about the Elba expansion potential. Maybe a long shot, but can you give an update on Gulf LNG as an export facility? I think it's fully permitted. Is that a project that's made any progress and any efforts there? You know, as we've talked about in the past, we have a regas customer at that location who is paying for that capacity. Obviously in today's market, that's not in high use, not in use generally at all. We have a customer, and they're a paying customer, and they reserve the capacity, and we made a deal. Now, we will work with that customer to see if there's something that would allow us to bring the potential for a brownfield liquefaction opportunity forward, but we don't have anything to announce there today. Thanks. Second one, sorry, another Permian expansion question, but a little different, I guess, than your usual business model. Since it's less capital intensive, how do you think about contract durations for a Permian gas pipeline expansion? Are you willing to go less than the 10 years you've historically targeted or maybe not even fully contract it? Yeah, no, I mean, I think we're thinking minimum of 10 years. You know, we will plan to sell all of this capacity. I think the market wants it. I think, like, honestly, we may very well be oversubscribed. I think it's a good opportunity to fully sell the project out. Both projects. Thank you. Thank you. Becca Followill with U.S. Capital Advisors, you may go ahead. Hey guys. Sorry, another Permian one. Acknowledging your comments, Steve, about that you're preparing for some of these items that you might need. Do you feel like that there is sufficient compression that either you have on hand or have ordered that you could do both of these expansions within 18 months, assuming that you FID them? Yeah. Again, we're reluctant. We're in a very competitive situation. Becca, I think what is fair to say is what I said, which is we've prepared. Okay. Okay? Thank you. The second one is on a new Permian pipe. Just in light of the Nationwide Permit 12 process that's underway, do you feel like you could build a new pipe under an NWP 12, or do you feel like you would need to get individual water body crossings? Yeah, it's first of all really important. I know you're not asking about the compression expansions on this question, but one of the great things about these are that they are very permit light, right? It's getting an air permit under a permit by rule arrangement at the TCEQ. We think we can avoid issues that would otherwise trigger a more active federal review by the Corps or anyone else. There's some good mitigation built into our plans to avoid endangered species, to avoid open water crossings, etc. We've got all that worked out. Your bigger question, though, Nationwide 12 has been open to attack, and it's been attacked. There's a process underway right now at the federal level where a lot of open-ended questions are being asked about should we change this? Should we change that? Should we change the other thing? There is some uncertainty around Nationwide Twelve right now, no doubt about it. Hopefully, that uncertainty resolves itself as we get closer to needing to use it for something like a big new greenfield pipeline expansion. We are, to be safe, evaluating in other contexts with smaller projects where we may be using Nationwide Twelve, evaluating how we could get individual permits if need be. Now, for the most part, what the Corps will point you toward is Nationwide 12. That's what it's there for. Use that. It's only prudent for us to evaluate if you end up in a problem there to have a plan B. We're developing those plan Bs. Perfect. Thank you. Thank you. At this time, we're showing no further questions in the queue. Okay. Thank you very much. Have a good afternoon. Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.