Welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode. Today's call is being recorded. If you have any objections, please disconnect at this time. I will now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Okay. Thank you, Ted. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, and the Securities 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 disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. Over the past few quarters, I've talked about our view of the future demand for natural gas with strong growth being driven by LNG exports, exports to Mexico, and electric generation which is benefiting from the tremendous needs of AI and data centers. Our viewpoint is consistent with most other energy leaders and analysts in the field. So, the next question is, what's the impact of this growth on a midstream company like Kinder Morgan? We believe it's substantial and positive. In fact, in my decades of experience in the mid-term arena, I've never seen a macro environment so rich with opportunities for incremental build-out of natural gas infrastructure. And at Kinder Morgan, we expect to be a major player in developing that infrastructure. In July, we announced the approximate $3 billion South System Expansion 4 Project, which is underpinned by long-term shipper commitments and designed to increase our Southern Natural Gas South Line capacity by approximately 1.2 Bcf per day, helping to meet growing power generation and residential commercial demand in the Southeastern US market. Today, we are announcing the expansion of our GCX system in Texas, which will enable our customers who have signed long-term throughput agreements to move substantial additional gas out of the Permian Basin. We expect to announce additional significant projects over the next several months that will allow us to expand and extend our network to better serve the needs of our customers and benefit our bottom line. As these projects come online, we should be able to grow our EPS, EBITDA, and DCF on a consistent and sustainable basis for years to come. And with that, I'll turn it over to Kim.

Thanks, Rich. I'll share a few points before passing it to Tom and David for more details. In the third quarter, earnings per share remained the same. EBITDA increased by 2% compared to the same quarter last year. For the year, we anticipate EBITDA growth of 5% and EPS growth of 9% compared to 2023, even though we expect to be slightly below our budget due to lower commodity prices and the slow start of our RNG facilities. The debt-to-EBITDA ratio is steady at 4.1 times. During the quarter, we added about $450 million in projects to our backlog, including the GCX expansion mentioned by Rich, a storage expansion on NGPL, and a new lateral serving a natural gas power plant. We placed around $500 million in projects into service, leading to a current backlog of $5.1 billion. Looking ahead, we see significant growth opportunities in natural gas, including LNG, exports to Mexico, power, and industrial growth. Current discussions on power opportunities exceed the 5 Bcf a day we noted in the second quarter. We estimate growth in the overall natural gas market to be around 25 Bcf a day over the next five years. There are various factors driving power demand, such as population and business shifts to the Southern United States, with states like Arizona, Texas, Georgia, and Florida already facing tight energy markets. Factors such as the CHIPS Act, low feedstock prices, and national security are contributing to onshoring and nearshoring. The increasing use of renewables necessitates more natural gas peaker plants to manage intermittent demand, and coal plant conversions are continuing to progress. Additionally, data center demand has surged. Regardless of the demand source, one project often leads to another. For instance, an LNG facility typically starts with a header pipe to transport gas from the nearest liquid market and eventually contracts for capacity upstream to secure better-priced molecules. Similarly, we’ve observed companies subscribing for capacity along different paths for supply diversity. There are comparable dynamics in LDC and power demand, where projects aim to expand existing pipeline capacity and extend efforts to ensure robust and varied supply. This situation reminds me of the adage that one thing leads to another. Regarding our future opportunities, some projects are quite large, ranging from $1.5 billion to $2 billion, while most will be smaller. As I mentioned last quarter, not every project will materialize, and larger ones may take longer to develop, yet the opportunities have been growing throughout this year, and discussions are becoming more targeted. As Rich pointed out, we've already approved two major projects totaling $3.6 billion A Rate, with $1.8 billion for KM-share which includes the Southern Natural Gas South System 4 Project and the GCX expansion. I expect that, as Rich indicated, we’ll continue to build on this backlog. It’s an exciting time to be in the midstream business. Now, I'll pass it to Tom for more details.

Thanks, Kim. Starting with the natural gas business unit, transport volumes increased 2% in the quarter versus the third quarter of 2023. Natural gas gathering volumes were up 5% in the quarter compared to 2023, driven by Haynesville and Eagle Ford volumes, which were up 10% and 9% respectively. Sequentially, total gathering volumes were down 5%. For the year, we expect gathering volumes to average 8% below our 2024 plan but 5% over 2023. We view the slight pullback in gathering volumes as temporary as higher production volumes will be necessary to meet the demand growth from LNG expected in the second half of 2025. Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation and storage capabilities in support of the growing natural gas market. In our Products Pipeline segment, Refined Products volumes were up 1%, and Crude and Condensate volumes were down 4% in the quarter compared to the third quarter of 2023. For the full year, we expect Refined Products volumes to be slightly below our plan at 2% over 2023. Regarding development opportunities, KMI's SFPP pipeline closed a successful binding open season during the quarter to add 2,400 barrels per day of additional refined petroleum products capacity on its Eastline system for transportation services from El Paso, Texas to Tucson, Arizona. The project can be expanded further and is expected to be in service during the third quarter of 2025. In our Terminals business segment, our liquids lease capacity remains high at 95%. Refining cracks and blending margins, though down from recent highs remain constructive and supportive of strong rates and high utilization at our key hubs in the Houston Ship Channel in New York Harbor. Our Jones Act tankers are 100% leased through 2024 and 97% leased in 2025, assuming likely options are exercised. The current market rates remain above our fleet average charter rate and we expect to re-contract at higher charter rates as contracts come up for renewal. The CO2 segment experienced lower oil production volumes at 6%, lower NGL volumes at 3%, and higher CO2 volumes at 3% in the quarter versus the third quarter of 2023. For the full year, we expect oil volumes to be roughly flat to budget. The Board approved two projects today associated with our acquisitions over the last couple of years. These projects include the development of a CO2 flood at the undeveloped leasehold adjacent to SACROC that we acquired in June and the second Phase of the CO2 flood development at Diamond M. We expect to spend a combined $145 million on these projects, resulting in a peak oil production of greater than 5,000 barrels a day. With that, I'll turn it over to David Michels.

Thanks, Tom. For the quarter, we're declaring a dividend of $0.2875 per share, which annualizes to $1.15, reflecting a 2% increase from our 2023 dividend. We generated revenue of $3.7 billion, a decrease of $208 million from the third quarter of 2023. However, the cost of sales also fell by $381 million, leading to a 7% increase in gross margin compared to last year. We reported net income attributable to KMI of $625 million and earnings per share of $0.28, both 17% higher than the third quarter of 2023. On an adjusted basis, we generated $557 million in net income and adjusted EPS of $0.25, which is unchanged from last year. We saw year-over-year growth in our natural gas and terminals businesses, primarily driven by contributions from our recently acquired South Texas midstream assets, increased performance from our natural gas transportation and storage services, and contributions from higher-growth projects. Our Products segment declined mainly due to lower commodity prices impacting our inventory valuations. The distributable cash flow per share was $0.49, flat compared to last year. We experienced a rise in sustaining capital expenditures compared to last year during the quarter, in line with our budget. For the full year, we expect sustaining capital to align with our budget. Overall, the quarter was relatively stable compared to last year, but on a year-to-date basis, performance has improved, with EPS up 9% and adjusted EPS up 5% compared to last year. As Kim mentioned, while we anticipate being slightly below our budget for the full year, we expect our full year adjusted EBITDA to increase by 5% compared to 2023 and our adjusted EPS to rise by 9% compared to 2023. At the end of the third quarter, our balance sheet reflected $31.7 billion in net debt, with a net debt to adjusted EBITDA ratio of 4.1 times, consistent with our quarterly budget. Our net debt has decreased by $150 million since the beginning of the year. We've generated $4.2 billion in cash flow from operations, spent $1.9 billion on dividends, and invested $2 billion in total capital expenditures, including growth, sustaining projects, and contributions to joint ventures. Additionally, we've utilized approximately $50 million in other working capital, leading to the overall $150 million decrease in net debt for the year. Now, I'll turn it back to Kim.

Okay. Thanks, David. Ted, if you'll come back on, we'll open it up to questions.

The phone lines are now open for questions. The first question in the queue is from John Mackay with Goldman Sachs. Your line is open.

Thank you for your time, everyone. You've discussed the growth potential you’re observing in the power sector. There are a few projects that aren't quite in the backlog yet, which I believe we previously referred to as a shadow backlog. I would like to know how the size of that compares to this time last year. Additionally, could you provide some insights on Mississippi Crossing and Trident in that context?

Sure. The opportunities have continued to grow compared to the beginning of the year and even more so since this time last year. We don't officially have a shadow backlog, but if we did, there would be a significant increase. The projects we have mostly consist of smaller, less risky endeavors that leverage our existing network and provide good returns. We also have larger projects in the pipeline. For example, we are in discussions with power plants in various states including Arizona, Arkansas, Texas, Mississippi, Louisiana, Wisconsin, and Colorado, and we are addressing Georgia's needs through the South System 4. On the industrial side, we are witnessing the development of battery and chip plants in Arizona, auto plants in Georgia, and petrochemical plants driven by onshoring and the CHIPS Act, along with low commodity prices providing affordable feedstock for these facilities. Export opportunities to Mexico are emerging from power plants, nearshoring, and LNG exports. We have carbon capture and storage projects in the petroleum sector and several blending opportunities. Recently, we added a 10 Bcf storage opportunity to our backlog. Overall, our backlog has grown significantly from last year, increasing from around $3 billion or less to over $5 billion now. Additionally, we updated our expected expansion capital expenditures from $1 billion to $2 billion per year to $2 billion per year. These developments indicate the growing opportunity set we see. As for the MSX project, I will let Sital provide more details about that and the open season.

Yes, John, this is Sital. So, as you've been talking about the last couple of calls, we've got two open seasons out there, our theme. We've been saying for a while that we've got a need for more molecules to move from West to East. So, what you have is two open seasons, one with Mississippi Crossing and one with Trident. That basically is getting molecules to where they're needed. Mississippi Crossing can be scaled up to 2 Bcf to get to the Southeast markets, obviously, to feed some of the Southeast customers that we're working with on South System 4. Trident is a project that gets gas from Katy all the way to the LNG corridor in Port Arthur. And so, we're excited about those projects. We're working with our customers. Needless to say, both of them are in kind of a competitive space. So, hopefully, we'll have more to share on the next call as it pertains to those.

And they just gave me the number on the backlog, third quarter last year was $3.8 billion. So, we've gone from $3.8 billion to $5.1 billion. So, that's a 34% increase in the backlog.

That's helpful information, thank you. For my second question, as we approach guidance in two months, I'm not looking for specific numbers, but I would like to understand how 2024 has compared to initial guidance, particularly regarding commodity softness. We can discuss how much of that might be temporary. Could you also share insights on other factors within the business that may be performing better or worse than expected, aside from commodities, and how those might trend into 2025?

On the natural gas side, we are experiencing some commodity impacts that are affecting gathering volumes, resulting in weaker performance compared to our budget. As Tom mentioned, gathering volumes have been impacted. Conversely, we have seen significant strength in our transmission assets, including transport contracts, storage, and PAL, which is providing some offset to the declines we are witnessing in commodity and G&P volumes. Looking ahead to 2025, the question will revolve around our expectations for G&P volumes, but it is still early to provide specifics. The first half of the year is likely to mirror 2024. As export LNG volumes start to come online in the latter part of the year, such as those from Corpus and Golden Pass, we anticipate a stronger environment. The winter weather will also play a role in this. Additionally, various segments, like products and terminals, have rate escalators, and we see potential upside from the Jones Act. Rising interest rates will also benefit us, along with our expansion projects and stabilizing our RNG facility. Ultimately, we'll need to assess G&P outcomes and commodity prices as they develop. We expect cash taxes to increase slightly, but overall, we will not be substantial cash taxpayers.

All right. That's fantastic. I appreciate the time.

The next question in the queue is from Michael Blum with Wells Fargo. Your line is open.

Thanks. Good afternoon, everybody. I wanted to just stay on the topic of the percolating gas, gas demand, gas projects. Given just the growing potential backlog of projects that you're looking at, where do you see CapEx trending over the next few years? I know you last quarter kind of raised it from $1 billion to $2 billion up to $2 billion plus or minus $1 billion of growth CapEx, but do you see that trending even higher over time? And any idea of where that could go?

Okay, Michael. At this point, I wouldn't say there's any change to our approximately $2 billion per year plan. When we refer to roughly $2 billion, that could be a bit more or less, possibly ranging from $2 billion to $3 billion or something similar. CapEx can be variable based on timing, so that's something to consider. We review this every quarter and just did so before this call, and we'll revisit it in January of next year. We aim to keep you updated, but there are no changes at this time. I'd also like to highlight that the cash flow we generate allows us to fund around $2.5 billion per year in CapEx directly from those funds. Additionally, we have some balance sheet capacity available if we need to finance projects and reduce leverage as they come up. Overall, we are well-positioned to fund projects, especially if we manage to increase that number.

Got it. That's great color. Thanks. And then my other question was really about expected returns. So, obviously, the backlog has lots of different projects, different sizes, types of projects. But if there's anything, just talk about trend-wise, are you seeing better returns on this project? It seems like the South System 4 Expansion was a really attractive multiple versus your total backlog. So, just wondering if you're seeing that trend overall. Thanks.

I mean, I think the returns that we are getting on these projects are pretty consistent with what we've achieved historically and what we've targeted. So, different projects come at different returns depending on how long it takes you to bring a project on, the multiple is likely going to be better to get to the same return because you've just got that, you've got that CapEx drag on the front end. But no, South System 4 is not substantially different than the projects that we've done historically.

The next question in the queue is from Theresa Chen with Barclays. Your line is open.

Hi, Theresa. Theresa?

Please check your mute button.

Can you hear me now?

Yes.

We can hear you.

Sorry about that. So, looking at your Mississippi crossing project, can you give us some color on the commercial drivers that would allow Kinder to win this project, assuming the binding open season is successful? Do you think this is in part driven by customers' desire to diversify sources of supply beyond the typical Northeast mid-Atlantic corridor?

Theresa, good question. One, I think as we've been saying before, with the advent of all this LNG coming on in the Gulf Coast, I think the markets are recognizing the need for incremental supply. And this is not only diversification of supply but actual access to physical molecules to be able to handle the upcoming growth. And so, I think reaching back to a point of liquidity where you have access to different basins in addition to the existing basins is kind of the play.

Got it. And then turning to a different part of your portfolio. With the recent success of one of your competitors in spinning out their liquids business, any thoughts on separating your products business from your natural gas assets to potentially reflect better value in each?

Yes, I believe that the businesses we own and operate are strategically beneficial when combined. We gain advantages from having both natural gas and products pipelines. For instance, our integrity team works across our operations, and we benefit from project management as well. If we were to separate those businesses, there could be certain disadvantages. Furthermore, if you assess the parts individually compared to the whole company, there is a notable discount in valuation. Therefore, there isn't much incentive to incur transaction costs and risks associated with separating the businesses. Additionally, potential disadvantages could arise on the general and administrative side and possibly on the debt side, depending on interest rates at the time of any transaction. A separation would need to be evaluated carefully, focusing on how differently the separated companies would perform in the market compared to their combined value, to justify such a move.

Next question is from Zack Van Everen with TPH. Your line is open.

Hey guys, thanks for taking my question. Maybe to start, could you guys touch on the recent decision with the U.S. courts on your Cumberland project and kind of what the process is there going forward?

Yes, sure. As you know, the Sixth Circuit estate, our Army Corps, and our Tennessee air and water permits prevent us from starting construction on that project. We believe that decision is incorrect and the analysis is flawed on multiple levels, including the standard used for the stay. This project involves delivering natural gas to a power plant that is transitioning from coal, and the FERC found that it would lead to a reduction in greenhouse gas emissions, which is beneficial from an environmental standpoint. Over the past decade, our permits have faced challenges from anti-fossil fuel opponents, despite the societal benefits. We have been successful in overcoming those court challenges, most recently when the DC Court of Appeals upheld our FERC permits for two different projects. We also succeeded in other courts regarding state and local permits connected to those projects. This is not a new situation for us; we are collaborating with the affected agencies, the Army Corps and TDEC, to determine the next steps, and we expect both agencies to vigorously defend those permits.

Perfect. That makes sense. And then maybe one on the FID on Gulf Coast Express. I think when looking back to Permian Highway, that took about a year. Is that a similar timeline you guys are looking at for this expansion?

Yes. The Permian Highway project took approximately 19 months. For this project, we're cautiously estimating around 22 months due to significant demand for compression and various electrical components. Nevertheless, we are aiming for a mid-2026 in-service date. It's not as quick as the 19 months for the Permian Highway, but we believe it's still a reasonable timeline.

Got it. Makes sense. Appreciate the time, guys.

Next question is from Jean Ann Salisbury with Bank of America. Your line is open.

Hi. Between the Gulf Coast expansion and Blackcomb, there's a lot of gas heading to the Agua Dulce area. Is there a risk that there won't be enough demand in the area in 2026, especially if LNG projects get delayed? And how do you see the GCX expansion is positioned for that risk?

That's a very good question. If there are any delays in the demand centers, especially for LNG, there could be some pricing exposure. However, we have discussed our downstream flexibility for our customers. This flexibility is important because, with variability, there will always be some volatility. Storage assets will be crucial as we approach that timeframe. While it's a possibility, it’s not something we consider likely at this point. We still don't have definitive answers.

And from our standpoint, we have long-term contracts with our shippers.

Yes. So, we've got long-term contracts with the shippers. I always thought point out that it's a potential for us to profit on our Texas Intrastate business where we do buy and sell some gas, and we try to back-to-back those, but sometimes we are in the daily markets. And so to the extent that that gas gets hit at Agua Dulce and we've got capacity on our pipeline, we can buy effectively cheap gas. And so that will be an opportunity for us. I think the other thing on that is, we do have a project that we've been working on to potentially expand our pipeline systems from Agua Dulce up into Katy. And so if that could create an opportunity for that project just depending on how long that dynamic was anticipated to persist.

That makes sense. Thank you. And then at your Investor Day, you kind of mentioned that you have 200 Bcf of market rate storage. Bringing that up to current market rates is going to be kind of a tailwind. Is that still a tailwind that you see over the next couple of years? Is that mainly still below kind of current rates, if that makes sense?

Yes. It's about 25% of our storage is market-based rates. Some of that we have rolled and some of it we still have to roll. But in terms of the strength of the storage market, the strength of the storage market is continuing and rates, I think are continuing to get a little bit stronger. On Monday, we talked about a three-year deal that we've done. That was a high watermark for us on the storage side. That was in five-turn service. So, I mean, very valuable storage, but we did hit a high watermark. So, I think that's still going to be a tailwind, but those contracts probably roll over a three-year period roughly. So, you probably roll a third of those a year.

Great. That's helpful. That's all from me. Thanks a lot.

Next question is from Neal Dingmann with Truist Securities. Your line is open.

Good afternoon, all. First, my first question, just more general on backlog. And I'm wondering, is it fair to assume that we should think of your backlog maybe staying around the $5 billion given, number one, it seems like you have a lot of opportunities you discussed, but you also have, I know, a number of projects that should come on to service in the coming quarters and just wonder how you would expect to think about this?

Yes. We haven't attempted to forecast our backlog yet, so I can't specify exactly where we're heading. However, it has increased from $3.8 billion a year ago. While we have some projects completing, there is potential to add significant projects along with smaller ones. If we successfully add those major projects, there's a possibility that our backlog will grow.

That's great to hear. And then just secondly, I know, a bit smaller, just anything you could add on the CO2 portfolio specifically. I know I think last quarter you mentioned just likely no material change in capital spend there. I'm just wondering, will this continue to be the case? I know you've got what, given the development of SACROC and North McElroy are different things, how should we think about that portfolio?

Yes. I think Tom mentioned in his comments that this morning our Board approved about $150 million for new CO2 flood projects this quarter. We expect that peak production will increase by an additional 5,000 barrels a day, which is a significant increase relative to our existing production. So, Anthony?

Yes. On an annual basis, we're spending probably $200 million a year on expansion. So, I think that just rolls into that program. So, I wouldn't expect a material increase at least in the near term.

Very good. Thank you both for the details.

Next question in the queue is from Jeremy Tonet with JPMorgan. Your line is open.

Hi. Good afternoon.

Hey, Jeremy.

Hey. Also wanted to give a belated happy birthday to David there.

Thank you, Jeremy.

You know how old he is?

I don't think I'm allowed to ask that. But just wanted to kind of pick up on a couple of pieces that were touched on a bit during the call. Kim, I recognize this is kind of an impossible question, but just at a high level, when we think about operating leverage for Kinder, there's weight and capacity on the gathering side. There's weight and capacity on the pipe side and just want to get a sense for, I guess, capital-light growth there. If the G&P really ticks up, if there's a call on gas, higher gas prices, if the peakers are really pulling because they have to run more given high power prices, how does that, I guess impact KMI?

I believe there is some capacity in gathering, particularly in the Eagle Ford, though we will need to add processing there. In terms of pipeline capacity, the Eagle Ford has ample resources. The Haynesville has a strong backbone as well, but we may need to incorporate additional laterals and possibly some treating based on developments in that area. It seems that adding a lateral could be necessary in the Bakken, but there are efficient opportunities for expansion in gathering and processing. Our transmission pipes are operating at nearly full capacity, as evidenced by the utilization figures we shared at our conference. Thus, I expect that additional benefits will arise as contracts renew. Furthermore, we can see some advantages from offering additional services during volatility events on those highly utilized pipes.

Got it. That's helpful there. And then just wanted to kind of touch on a little bit more as it relates to the power demand, large customers as well as data centers, potentially. How far upstream could you guys see Kinder going? Could Kinder provide behind-the-meter gas solutions, be it providing the gas or if there was a contract structure that was attractive, even providing the power itself with the gas generation? Just wondering how you think about the opportunity set here.

Yes, we can provide gas directly to a power plant regardless of whether it's behind or in front of the meter. The distinction of being part of the transmission grid doesn't affect us. We can supply gas in either case. We've occasionally discussed the possibility of placing a power plant next to one of our storage facilities, which would offer high reliability for that power plant and potentially for a nearby data center as well. While we don't have concrete plans at this time, it is something we are considering.

And the next question in the queue is from Keith Stanley with Wolfe Research. Your line is open.

Hi. Thank you. Just two clarification questions. So, the first one, I think you said you could fund $2.5 billion a year of growth CapEx out of cash flow. Would you be comfortable even going higher than $2.5 billion a year on a recurring basis, or do you view $2.5 billion as kind of a cap within your financial framework?

Currently, our debt-to-EBITDA ratio stands at 4.1 times, and we anticipate finishing the year close to 4 times. The maximum we expect for debt-to-EBITDA is 4.5 times, where each 0.1 change equates to approximately $700 million. We could consider using debt to fund some additional capital expenditures, provided we are confident that the cash flows generated by these projects will justify the investment over time, aligning with our target returns, thus allowing the debt-to-EBITDA ratio to decrease in the future. Additionally, we believe there is ample opportunity to find capital for strong return projects. For significantly large projects, we can also engage partners. Therefore, I don’t foresee any issues in funding worthwhile projects with solid returns, whether we handle it all ourselves or collaborate with private equity or other partners.

We think we can maintain a strong balance sheet and still accommodate our needs for CapEx.

Thanks for the clarification. I wanted to revisit the court's question. Some of your competitors have experienced greater impacts, but do you perceive an increased risk associated with court reviews on projects following the Chevron decision? Are there different approaches you can take regarding permitting strategies or the timing of capital deployment and return requirements to address potential challenges if courts become more problematic for new infrastructure?

What I would say regarding the Chevron doctrine and this decision is that I don't believe the Chevron doctrine influenced the decision we received on Cumberland. This is something we've been observing for a while. For instance, looking back at PHP, we faced five or six separate challenges while navigating that project and successfully handled around 14 different hearings. Therefore, this is a trend we've seen for some time. There are certainly steps we can take to improve the situation. As we process permits, obtaining a permit alone isn't enough; we must ensure that we cover all necessary aspects and conduct the required work to make the permits we obtain defensible in court. I don't currently see this situation as being more challenging than what we've faced before. Stakeholders should be prepared for challenges and understand that we'll integrate these considerations into our strategy. We'll factor this into our capital deployment and develop ways to address these concerns as we undertake projects, just as we have over the past decade.

Thank you.

And I'm showing no further questions at this time.

Okay. Well, thank you all for joining us this afternoon. Have a good evening.

This concludes today's call. Thank you for your participation. You may disconnect at this time.