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spk06: 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 1 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.
spk00: 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 include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and 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 Koehn and the team will tell you, the year is off to a good start. But I want to 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 US 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, but 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 remove 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.
spk14: Steve? All right, thanks, Rich. So 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 experience 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 so 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 timeframe 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 Connetrix 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 misplanned 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 such that our updated sensitivity is about 4 million. We expect continued strength in our base business, but we also expect to experience some negative impact from cost pressures, due both to additional higher costs on certain materials, chemicals, parts, and vehicle fuel. Still, taking all of this into account, we are predicting that we will be above planned for the year. In summary, we're... Okay.
spk11: Thanks, Steve.
spk09: I'll go through the segments, starting with natural gas. Our transport approximately 0.9 million first quarter of 2021, and that was driven primarily by increased LNG delivery, generally colder weather, partially offset by the continued decline in Rocky's production, and a pipeline outage on EPNG.
spk11: Deliveries to LNG facilities off of our pipes average approximately 6.2 million decatherms per day, but their deliveries to LNG facilities, as Rich mentioned, remains around 50%.
spk09: Exports to Mexico were down . Overall deliveries to power plants were up 5%, and we believe that natural gas power demand is becoming more inelastic relative to coal.
spk11: Deliveries to LDCs and industrials also increased. The overall demand for natural gas is very strong. Both our internal and WMAC numbers project between 3 and 4 BCF of demand growth for 2022. And in our numbers, we project growth in oil power exports to Mexico and LNG exports. Our natural gas gathering volumes were up 12% in the quarter compared to the first quarter of 21%. Sequentially, volumes were down 6%, with a big increase in Hainesville volumes, which were up 14%, more than offset by lower Eagleburg volumes, which were impacted by contract termination. Overall, our budget projected gathering volumes in the natural gas segment to increase by 10% for the full year, and we are currently on track to exceed that number. In our product pipeline segment, refined product volumes were up 7% for the quarter. Compared to the pre-pandemic levels, using Q1 of 19 as a reference point, road fuels were down about half a percent as we went through the quarter, so higher prices may be starting to impact demand.
spk09: Crude and condensate volumes were down 4% in the quarter versus the first quarter of 21.
spk11: Sequential volumes were flat with a reduction in the Eagleford offset by an increase in the Bakken. In our terminals business segment, the liquids utilization percentage remains high at 92% to about 95%. Our RAT business, which serves consumers with domestic demand, was up nicely in the first quarter.
spk09: Our pub facilities were up nicely. As Steve said, we've business with all 16 vessels currently sailing under firm contracts, and day rates are still improving, though still lower relative to expiring contracts.
spk11: On the bulk side, overall volumes increased by 19%, driven by pet coke and coal, which more than offset lower steel and ore volumes. In our CO2 segment, crude volumes were up 7%.
spk09: CO2 volumes were down 9%, but that was due to the expiration of a carried interest following payout on a project in 21.
spk11: 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 the other half due to strength in our base business. As Steve said, we currently project that we will exceed our full year 2022 plan. We've not specifically quantified the outperformance because one, it is relatively early in the year, And two, there are a lot of moving pieces, commodity prices, gathering volumes, inflation, regulatory demands, and interest rates, to name a few. I'll turn it to David Michaels.
spk12: All right. Thank you, Kim. So for the first quarter of 2022, we're declaring a dividend of $0.2775 per share, which, as Rich mentioned, is $1.11 annualized. 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. And our net income was $667 million down from the first quarter of 2021, but excluding the contribution from Winter Storm URI last come during the first quarter of 2021 would have been $569 million. So 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, but 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,
spk09: our Texas interest rates, as well as greater volume on Kinderhawks.
spk12: Our product segment was up $36 million, driven by increased refined product volumes and favorable price impacts, partially offset by higher integrity costs, and our terminals business up $11 million versus 2021, with greater contributions from our bulk terminals, driven by higher pet coke and coal volumes, as well as growth in our liquids terminals business due to expansion projects contributing to 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 deficit. 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 for hedging activity. And 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.
spk09: And we also had a rate case reserve refund paid.
spk12: And that explains the majority of the $191 million for the quarter. And with that, I'll turn it back to Steve.
spk14: Okay. Thanks, David. Michelle, if you'd come back on and open it up for questions. And 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, et cetera. So, Michelle, open it up, please.
spk06: Thank you, sir. At this time, if you have any questions or comments, you may press star 1. Please unmute your phones and state your first and last name and company name when prompted. Our first caller is Jeanne Ann Salisbury with Bernstein. You may go ahead. Hey.
spk07: I just wanted to ask about the potential compression expansion. How are customers comparing the compression expansion option versus a new build? Are the rates similar? Obviously, you mentioned that the timeline to market is faster, which is great, but maybe the compression rate is lower since the fuel cost is higher. Just wanted to understand which was kind of more attractive to customers.
spk08: Very good. Tom Martin, president of our gas group. Yes, I mean, can't get too specific about overall rates because it's a competitive situation, but I think I'll just say it is attractive to the market in total. As Steve said, it is more fuel costs, but that will be at least partially offset by the fixed fee that's associated with it. But getting this in service in 2023 is will really help alleviate a worse as we get into 2020 and 2023. So 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.
spk07: Great. That's helpful. And I guess on that topic, is 18 months to add compression and some
spk08: 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. But I think in these times that's probably indicative, if not longer.
spk07: Okay. And then just one more follow-up on this, if I may.
spk09: Are you going to ask the privates to sign up this time again? and more constraints on flaring and everything, or is it the same mix of customers as in the past?
spk08: Again, hard to speculate specifically on customers, but I think I would say it's a broader that we may have seen on the Greenfield project.
spk09: So speaking, I think, really to the point you're making is that there are –
spk08: There's a broader set of customer interest this time.
spk06: Great. That's helpful for me. That's super helpful. Thank you. Thank you. Our next caller is Colton Bean with Tudor Pickering Holt & Company. So you may go ahead.
spk13: Good afternoon. So you all mentioned seeing higher costs in the release. Can you just elaborate on where you're seeing those costs hit the system, whether that's materials, labor, or other areas?
spk14: Yeah, so there are two categories to the plan, okay? So we've added some incremental integrity and maintenance work to the plan, and so that's not an ongoing or recurring thing, but we're doing some work here and probably next year. That's one thing is we haven't experienced a great deal of inflation to date. We experienced as Normal, when commodity prices are up, you see it in the oil field, right?
spk09: But commodity prices are up. The revenues are up to go with it.
spk14: So we're seeing some there. The other places where we're seeing inflation, we projected a little inflation, but the places where we've actually experienced it are obviously fuel for our trucks, okay, and for our materials, you know, steel costs. and even though raw steel has come down a little bit, it's been down then up a little. So it's some materials, equipment, lubricants, fuel.
spk13: Great. I appreciate that. And then Rich mentioned the need for incremental optimization opportunities available to you all at Elba Island, or alternatively, if market interest has increased, could that be a potential development?
spk09: That's your candidate.
spk08: Yeah, so the current project, there certainly is an opportunity to do an expansion there, a small-scale expansion. We had those discussions a couple years ago, obviously with what is happening now. It's very early days to say whether there's a real potential there, but, you know, suggest that maybe something worth looking at.
spk14: 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 in our network. We can participate in that market and the growth opportunity by serving them and serving them well. Our storage assets along our network, and particularly with a lot of that growth coming in Texas and Louisiana where our footprint is especially robust. And so, you know, ELBA is something we will evaluate, as Tom said, and we'll work with our customer on that. But really a big play for us in the trend in storage service providers standpoint.
spk13: Got it. That's helpful. Appreciate that, Tom.
spk06: Thank you. Our next caller is Jeremy Tenet with J.P. Morgan. Sir, you may go ahead.
spk15: Hi, good afternoon. Good afternoon. Just wanted to see with the compression expansions, if you are able to provide any thoughts with regarding to capital outlay there for us to kind of frame it. You talk about being more capital efficient than a greenfield. And then 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 been in the past? And so presumably there's going to be need for incremental pipe beyond these expansions pretty quickly, at which point does that mean?
spk08: Yeah, again, I don't think we want to get into capital discussion again in a competitive environment on the expansion project, but I think your second point, Yeah, I think you're exactly right. The market will fill up relatively quickly. We're estimating a greenfield pipe will now be needed sometime in 2026 after all the expansions are done to fill the immediate need. And so with that, given the timeline on doing greenfield type projects, that would lend itself towards and that might be sometime early next year for that kind of a project.
spk15: Got it. That's helpful there. And then just wanted to kind of pivot towards you discussed this GHG collaboration study with other partners in midstream here, and just wondering if you could expand the project.
spk08: Yeah, I mean, I think whole LNG markets, are driving methane intensity type volume with our good customer and support of that initiative and really what this initial effort is a pilot program to help identify methane intensity on specific assets at specific locations with hope that that will broaden and ultimately support a certification process that will help your mark lower methane-intense gas going to international markets.
spk09: Jeremy, I'd just add to that that we have seen a bit of an inflection this year.
spk14: We've been talking about our low methane emissions intensity and marketing that as part of our service offerings. We've been doing that for a while, and we got a deal last year, and we got a couple of deals following that. We got a terror filing on TGP. There's information about 25% of the natural gas produced in the U.S.
spk09: today could qualify. And in the future, we're seeing evidence of that now. Just to add on real quick there, do you see this as something that increases price?
spk15: profit or is it cost of doing business or how do you think about how this goes?
spk08: Yeah, about time on the shoot. Truly to say that, I mean, I guess my thought is that the ancillary services that come out of responsibly sourced gas, pooling efforts, as well as some of the certification process as we go forward.
spk09: But, you know, I
spk08: 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.
spk15: Got it. That's helpful. Thank you.
spk06: Thank you. Let me go ahead.
spk02: Good afternoon. Good afternoon, everyone. Maybe to start off on capital allocation, you talked about EBITDA guidance of roughly $7.2 billion being favored to the analysts today.
spk09: Have any assumptions changed from January? I guess in other words, you know, have CapEx
spk02: needs been pulled forward with the GCX and PHB expansions or the potential if FIDA new permanent pipe impacts Kinder's process around potential buybacks this year and next? Thanks.
spk14: There's been no change in the principles. We are focused on making sure we keep the balance sheet strong and that we fund available capital projects that provide good MPV at well above our weighted average cost. cost of capital and returning value to shareholders with the dividend increase that we're talking about today as well as share repurchases. So 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 past. We're in to the year a good amount now, and I think we're still confident coming forward. We'll still have additional capacity beyond that. David, anything you want to add? No, I think you covered it. Okay.
spk02: Yeah, that's super helpful. Maybe as a follow-up on the Ruby bankruptcy proceedings, just kind of curious if you could talk about Tender's position as, you know, it seems like there's conflicting views on, you know, either handing over the pipeline to the bondholders versus looking to repurpose the pipe for the long-term, for the long-term returns.
spk09: I thought it would be helpful. The overall message on Ruby is the same as it's been for a long time, which is we're going to make decisions here that are in the best interest of KMI shareholders.
spk14: We're hopeful that as we enter into this new process that we're going to be able to work out reasonable resolutions. We continue to operate reasonably. the pipeline, and I believe that's what makes sense in the longer term. And I think you just have to separate out rhetoric in the courtroom from, you know, reality here. And so we'll continue to work in a constructive way with our counterparties.
spk02: Appreciate the call. Have a good day, everyone.
spk06: Thank you. Our next caller is Chase Mulvihill with Bank of America. You may go ahead.
spk09: Good afternoon. I guess first question, I just wanted to come back to the natural gas egress discussion around the Permian.
spk05: I think many investors thought that you'd probably see an announcement alongside today's results for railroad 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. And then you said 18 months kind of, you know, I guess to get in service with sanction. Are you ordering any long lead time items that could possibly, you know, move things up inside of 18 months? And then last one is just opportunities to expand or do expansions outside of kind of 42-inch acquisitions.
spk09: Do you see any opportunities there?
spk14: I'll start and ask Tom to correct anything I get wrong here. But 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. And so that has turned up the heat and turned up the volume on commercial discussions. And 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. But we're not going to project a particular time. It didn't come alongside the announcement today because we get contracts before we go. And so we're working on that, and we're working fast and hard on that. I'm not going to talk about specific commitments, but I'll just say that we've been – 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.
spk05: Okay. Any changes to when you think this bottleneck will be a bottleneck?
spk08: I think sooner. Early, you know, later this year, it begins in early 23. 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.
spk05: Okay. Last one on repurposing assets. Could you talk about opportunities that you see to repurpose some of your underutilized assets?
spk09: And then do you think this could be more near-term opportunities or really just really long-term opportunities you see to repurpose assets?
spk14: You know, 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.
spk05: Okay, perfect. I'll turn it over. Thanks, everybody.
spk06: Thank you. Our next caller is Michael Lapidus with Goldman Sachs. You may go ahead.
spk04: 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, gas storage rates, the tenor of new gas storage contracts, and whether there's a physical need for expansion of gas storage capacity?
spk08: A good question. A lot of discussion in that area. We have seen on contract renewals, 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 taking a hard look at doing that. 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 to our acquisition of Stagecoach was quite timely as well, kind of right in the middle of this whole trend. And 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.
spk04: Got it. That's super helpful. Just curious, when you get an, and I know it's going to vary by site, obviously, but 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?
spk08: 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 two-year timeline, maybe slightly longer if you're talking about leaching additional caverns. Again, it depends if it's a brownfield-type opportunity or a greenfield opportunity. But I think that's generally, I would say, the timeline I would think about as you talk about
spk04: expansion opportunities got it and then one last one and hate to do back-to-back here but different topic just curious how you're thinking about growth in the haynesville from here um after a pretty solid start to the year kind of what you think the trajectory is and and whether you think haynesville take away towards the gulf coast starts to get tight whether you guys play a role in that
spk08: Absolutely, and we've certainly seen tremendous growth, you know, year over year, quarter over quarter in our gathering assets, about $300,000 a day, quarter over quarter, and we're forecasting upwards of half a BCF a day, year over year, full year forecast, 22 versus 21. Yeah, and you're absolutely right. I mean, I think as that growth accelerates, not only on our asset, but other assets in the in the basin, you know, egress out is going to become more critical. I think there are some expansion projects that are probably more economical than an incremental greenfield, but I think, you know, we expect 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.
spk04: Got it. Thank you, guys. Much appreciated.
spk06: Thank you. Keith Stanley with Wolf Research. You may go ahead.
spk03: Hi. Thank you. I had two quick follow-ups. First, Steve, you talked to the Elbe 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?
spk14: 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, but 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.
spk03: Thanks. Second one, sorry, another Permian expansion question, but a little different, I guess, than your usual business model, but 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 contracted?
spk08: Yeah, no, I mean, I think we're thinking minimum of 10 years, and we will plan to sell all of its capacity. the market wants it i think like honestly we may very well be oversubscribed so i think it's a good opportunity to fully sell the project out both projects thank you thank you becca fallowell with u.s capital advisors you may go ahead hey guys um sorry another permian one on
spk01: 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'd them?
spk14: Yeah, again, we're reluctant. We're in a very competitive situation. In fact, I think what it's fair to say is what I said, which is we've prepared. Okay, thank you.
spk01: 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 that, under NWP 12, or do you feel like you would need to get individual water body crossings?
spk14: Yeah, so it's, first of all, really important on the, and 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. 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, et cetera. So 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. So there is some uncertainty around Nationwide 12 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. But we are, to be safe, evaluating in other – contexts for smaller projects where we may be using Nationwide 12, 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. But if we were, it's only prudent for us to evaluate if you end up in a problem there to have a Plan B. And so we're developing those Plan Bs.
spk06: Perfect. Thank you. Thank you. And at this time, we're showing no further questions in the queue.
spk00: Okay. Thank you very much. Have a good afternoon.
spk06: And thank you. This concludes today's conference call. You may go ahead and disconnect at this time.
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