Good afternoon, and welcome to the Quarterly Earnings Conference Call. 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. I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you, sir. You may begin.

Thank you, Michelle. Before we begin, I'd like to remind you, as I always do, that KMI 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 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 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 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 of 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 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 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 a long natural gas infrastructure.

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 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 such that our updated sensitivity is about $4 million per $1 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 as well as some 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 plan for the year. In summary, we're doing very well. And with that, I'll turn it over to Kim.

Okay. Thanks, Steve. I'll go through the segments, starting with Natural Gas. Our transport volumes there were up 2% or approximately 0.9 million dekatherms per day versus the first quarter of 2021, and that was driven primarily 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. That's a 32% increase versus Q1 of '21. Our market share of deliveries to LNG facilities, as Rich mentioned, remains around 50%. Exports to Mexico were down in the quarter compared to Q1 of '21 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 Bcf and 4 Bcf of demand growth for 2022. In our numbers, we project growth in all major categories: residential-commercial, 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 '21. 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 contract termination. Overall, our budget projected gathering volumes in the Natural Gas segment increased by 10% for the full year, and we are currently on track to exceed that number. In our Products Pipeline segment, refined products 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 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 '21. Sequential volumes were flat with a reduction in the Eagle Ford offset by an increase in the Bakken. In our Terminals business segment, the liquids utilization percentage remains high at 92%. If you exclude tanks out of service for required inspection, utilization is about 95%. 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 dynamics, were also up significantly. As Steve said, we've seen some greenshoots 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 pet coke and coal, which more than offset lower steel and ore volume. In our CO2 segment, crude volumes were essentially flat compared to Q1 of '21, 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 '21. 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. But we expect the upside to outweigh the downside.

All right. Thank you, Kim. So for the first quarter of 2022, we are 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 nonrecurring 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. But excluding the contribution from Winter Storm Uri last year, our net income 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. The 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, our Texas Intrastate as well as greater volume on KinderHawk. Our Products 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 was up $11 million versus Q1 of 2021 due to 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, contributions, and an unfavorable impact from Winter Storm Uri during 2021. And those were partially offset in the Terminal 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 nonrecurring 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 4.4x, that's up from 3.9x at year-end 2021. But excluding the nonrecurring EBITDA contributions from Uri, the year-end ratio would have been 4.6x. So we ended the quarter favorable to our year-end recurring metrics. 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. 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, and we also had a rate case reserve refund paid, and that explains the majority of the $191 million for the quarter. And 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. 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 as you have questions about our different segments and their performance and outlook, etc. So Michelle, open it up, please.

Our first caller is Jean Ann Salisbury with Bernstein.

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?

Very good. Tom Martin, President of our Gas Group.

Yes. I mean, I 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 has more fuel costs, but that will be at least partially offset by the fixed fee associated with it. I think the key is speed to market, and that's the message that we're hearing from our customers: 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. So not ready to call this a win yet, clearly. We've got a lot of work to do, but getting some good feedback.

Great. That's helpful. And I guess on that topic, is 18 months to add compression and some of the things kind of longer than a similar project in the past? Is it due to supply chain issues going on? Or am I just too demanding?

Yes. I mean it may be somewhat longer, but 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.

Okay. And then 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 going to likely be the same mix of customers as in the past?

It's difficult to specifically comment on individual customers, but I believe there is a wider range of customer interest now compared to what we have experienced with greenfield projects. So, to address your point, I think there is indeed a greater diversity of customer interest this time.

Our next caller is Colton Bean with Tudor, Pickering Holt & Company.

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?

Yes. There are two main reasons for the higher costs. First, we've increased the scope of our work by adding additional integrity and maintenance tasks to our plan. This isn't a result of inflation but rather an expansion of the work we're taking on, which will take place this year and likely next year. The second reason is that we haven't faced significant inflation so far. However, as usual, when commodity prices rise, we see that in the oil field, which has led to increased revenues. While we anticipated some inflation, the areas most affected have been fuel for our trucks and equipment, where prices have risen. Additionally, costs for lubricants and certain materials like steel for equipment have also gone up. Although raw steel prices have fluctuated slightly, other materials, equipment, and fuel costs are on the rise.

Great. Appreciate that. And then Rich mentioned the need for incremental U.S. LNG. Are there any optimization opportunities available to you all at Elba Island? Or alternatively, if market interest has increased, could that be a potential divestiture candidate?

Tom?

Yes. So the current project is fully utilized by our customer. There certainly is an opportunity to do a small-scale expansion there. We had those discussions a couple of years ago; obviously, with what is happening now, we're dusting that off again. Again, very early days to say whether there's a real potential there. But overall, the market opportunity suggests that may be something worth looking at.

And Colton, the thing I'd add to that is just that 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. And so 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. And so 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 here is to be able to bolster what we do from a transportation and storage service provider standpoint.

Our next caller is Jeremy Tonet with JP Morgan.

Just wanted to see with the compression expansions if you are able to provide any thoughts regarding the 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. The pace of that project given how it's going to take longer to build a pipeline today than it did in the past and so presumably, there's going to be a need for incremental pipe beyond these expansions pretty quickly, at which point the Permian Pass could service that need.

Tom?

Yes. Again, I don't think we want to get into capital discussions again in a competitive environment on the expansion project. But I think your second point. Yes, 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 and given the timeline on doing greenfield-type projects, I mean, that would lend itself towards an FID sometime early next year for that kind of a project.

Got it. That's helpful there. And then I 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 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?

Yes. I mean, I think holistically international LNG markets are driving the bus on getting RSG and lower methane intensity type volumes. And so we're certainly working with our good customer in 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 this will broaden and ultimately support a certification process that will help earmark lower methane-intense gas going to international markets.

And Jeremy, I'd just add to 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. And by our estimation, about 25% of the natural gas produced in the U.S. today could qualify. And if you take all their targets into account, you get up to one-third. And so we think that this is going to be a point of distinction in the future, and we're seeing evidence of that now.

And 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 how this goes?

Yes. Well, Tom, go ahead.

Too early to say. But 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. But I think right now, it's more about identifying what we can do and what we can do on a large scale in the near term and identifying ways to harness that for the market.

Our next caller is Brian Reynolds with UBS.

Maybe to start off on capital allocation. You talked about EBITDA guidance of roughly $7.2 billion being favored to the upside versus the downside as you kind of sift through the global macro uncertainty. 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, have CapEx needs been pulled forward with the GCX and PHP expansions or the potential of FID a new Permian pipe impacts Kinder's process around potential buybacks this year and next?

Yes, 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 NPV, good NPV and well above our weighted average 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 budget. And we continue to look for those. But we're 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 want to add?

No, I think you covered it.

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 it seems like there's conflicting views on either handing over the pipeline to the bondholders versus looking to repurpose the pipe for the long term for additional purposes and potentially at the expense of margin in the medium term. Any color would be helpful.

Yes. So the overall message on Ruby is the same as it's been for a long time, which is that we are going to make decisions here that are in the best interest of KMI shareholders. 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 the pipeline and believe that's what makes sense in the longer term. And I think you just have to separate out rhetoric in the courtroom from reality here. And so we'll continue to work in a constructive way with our counterparties.

Our next caller is Chase Mulvehill with Bank of America.

I guess, first question, I just wanted to come back to 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 in 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, I guess, to get in service with sanction, are you ordering any long lead-time items that could possibly move things up inside of 18 months. And then the 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. We're not yet discussing timing. It’s safe to say the market is very interested and recognizes the upcoming capacity constraints, which has intensified commercial discussions. Given the necessary timeframe and our ability to bring products to market quickly, we feel confident in these discussions, but we won't commit to a specific timeline. The announcement today didn’t include a timeline because we secure contracts beforehand. We’re actively working on this and moving quickly. While I can’t discuss specific commitments, I can say we have been addressing the supply chain challenges in the marketplace and have taken appropriate steps to manage that risk.

Okay. And any changes to when you think this bottleneck really festers in the Permian? I think you said last earnings call, you said year-end '23. Is that kind of still the timeline of when you expect to see a bottleneck?

I think early this year, you can look at the financial markets, and they suggest that 2023 might face significant challenges. So yes, it's essential for us to exit that area as soon as possible.

Okay. Last one on repurposing assets. Could you talk about opportunities that you see to repurpose some of your underutilized assets? And then do you think this could be more near-term opportunities or really just long-term opportunities you see to repurpose assets?

We have one project in mind where we're actively considering repurposing. It's not a significant aspect of our current commercial activities, but it remains something we're evaluating.

Thank you. Our next caller is Michael Lapides with Goldman Sachs.

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.

Yes. No, a lot of discussion in that area, and 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. And I think there are opportunities to expand our storage facilities, especially in Texas. We're taking a hard look at doing that, and there seems to be a lot of interest in it. So on both the power customers as well as local distribution customers, especially in Canada, Texas. 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, we're performing well over our acquisition model assumption on that asset, especially as we integrate that with our Tennessee asset as well.

Got it. That's super helpful. Just curious, when you get a customer or a series of customers interested in expanding your existing gas storage facility, how should we think about the process and the timeline to actually be able to do so?

Yes. 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, that's probably a two-year timeline. So 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 we talk about expansion opportunities.

Got it. And then one last one, and I hate to do back-to-back here, but a 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?

Yes. So we've certainly seen tremendous growth year-over-year, quarter-over-quarter in our gathering assets, I mean about 300,000 a day quarter-over-quarter, and we're forecasting upwards of 0.5 Bcf a day year-over-year, full-year forecast '22 versus '21. Yes, and you're absolutely right. I mean, I think as that growth accelerates, not only on our asset but other assets and in the basin, 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 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. So we certainly are looking at that. I don't have anything that we're anywhere close to talking more about today, but we certainly see that as a potential opportunity.

Thank you. Our next caller is Keith Stanley with Wolfe Research.

I had two quick follow-ups. First, Steve, you talked to 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?

Yes. 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.

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 Permian Gas Pipeline expansion? Are you willing to go less than the 10 years you've historically targeted or maybe not even fully contracted?

Yes. No. I mean, I think we're thinking a minimum of 10 years, and we'll plan to sell all of this capacity. I think the market wants it. I think, like honestly, we may be oversubscribed. So I think it's a good opportunity to fully sell the project out, both projects.

Thank you. Our next caller is Becca Followill with U.S. Capital Advisors.

Sorry, another Permian one. I acknowledge in your comments, Steve, about that you're preparing for some of these items that you might need. Do you feel like 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?

Yes. We're very much aware of the competitive situation, Becca. I think it's fair to say that we are prepared.

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?

Yes. It's really important to note that while you're not asking about the compression expansions in this question, one of the advantages is that they require minimal permits. We believe we can avoid complications that could otherwise lead to a more intensive federal review. Our plans include effective measures to prevent impacts on endangered species and water crossings, so we have that covered. However, regarding Nationwide 12, it has faced challenges and is currently under scrutiny at the federal level, leading to a number of open questions about potential changes. This creates some uncertainty around Nationwide 12. We hope this uncertainty will be resolved as we approach the need for it in a significant pipeline expansion, but to be cautious, we are exploring alternatives for smaller projects that may also utilize Nationwide 12, as well as how we could secure individual permits if necessary. Generally, the core is inclined to direct us toward Nationwide 12, as that is its primary purpose. However, it makes sense for us to have a backup plan in case issues arise, so we are working on those contingency options.

And at this time, I am showing no further questions in the queue.

Great. Thank you very much. Have a good afternoon.

And thank you. This concludes today's conference call. You may go ahead and disconnect at this time.