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, you may disconnect at this time. I’ll now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Ted. And as usual, before we begin, I’d like to remind you that KMI’s earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities Exchange Act of 1934, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full 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. Now today, Steve, Kim and David will take you through the details, but we believe 2023 is off to a good start. While in a company our size, there are always lots of moving parts, I think 2023 will be a solid year for KMI, and that with our capital expenditure program, we are positioning ourselves well for 2024 and beyond. At both the Board and management level, we remain committed to transparency and utilizing our strong cash flow to benefit our shareholders by maintaining a strong balance sheet, funding capital projects that produce returns well in excess of our cost of capital, paying a healthy and growing dividend, which, by the way, in terms of yield, is one of the top 10 in the S&P 500, and repurchasing our shares on an opportunistic basis. In addition, through our investments in renewable natural gas, renewable diesel, and carbon capture and sequestration facilities, we are participating in the transition to cleaner energy. Let me conclude by reiterating our view, consistent with that of most energy experts worldwide, that fossil fuels will supply the great majority of the planet's energy needs for decades to come. For example, the recent IEA World Energy Outlook predicts that fossil fuels will supply 62% of the world's energy demand in 2050. Just this week, our Assistant Secretary of Energy stated that, given the current state of events, 'the world absolutely needs new gas investment.' While we expect that renewables will experience rapid growth over the coming years, the demand for energy as a whole will also increase substantially, thus driving the continued use of fossil fuels, with natural gas playing an especially important role in the coming energy transition. This outlook deflates the argument of those investors who avoid our segment because they do not believe our assets will produce long-term value. And with that, I'll turn it over to Steve.

All right. Thanks, Rich. I'll make a few key points about our business, and then Kim and David will cover the substance and details of our performance, and then we'll take your questions. The overview is this. Our balance sheet is strong, our backlog of projects is up, and our largest business, natural gas, continues to show growing strength. A couple of more details on each of those. We built our budget for this year with balance sheet capacity available to enable opportunistic share repurchases and incremental investment opportunities at attractive returns, and we have done both. Second, the backlog projects are attractive returns in aggregate, well-above our cost of capital. At Investor Day, every year, starting with the 2015 to 2017 period, we have shown you on an EBITDA multiple basis how we perform in those investments relative to our original assumptions, and we have performed very well. It's currently a challenging time from a supply chain standpoint, but we expect to deliver the current slate of projects even with challenges here and there at very attractive returns. Our current backlog is $3.7 billion, up $400 million quarter-to-quarter, and had an aggregate EBITDA multiple of 3.5x. Third, on renewals, we showed at the beginning of the year how our base business renewals in the 2023 budget are showing more increases, the decreases especially in our natural gas business as the network tightens with increasing supply and demand. So a strong balance sheet, a growing backlog, and good signs in our base business. A few other broad points about the macro backdrop underpinning this performance. First, as it’s becoming clear as time goes on and as Rich mentioned, hydrocarbon infrastructure is going to be needed for a very long time to come in its current use. The world needs reliable and affordable energy to advance human development, and it needs natural gas transportation and storage assets to backstop renewables. Second, our assets are also well positioned for the energy forms of the future. You can see that with the renewable liquid fuels and renewable feedstocks projects in our products and terminals businesses. Third, our existing natural gas transportation and storage network is growing more valuable as the grid tightens with increasing demand over time and increasing volatility. Compounding this effect is the difficulty of siting new infrastructure in many parts of the country. The value of the network was on display in the first quarter, where we had strong performance in our gas business and what was otherwise, except for the West, a mild and unremarkable winter. Finally, on the other hand, our network is well positioned for expansion in those parts of the country where it is possible to build new infrastructure, the Gulf Coast primarily. Our gas transportation and storage network is well positioned in Texas and Louisiana, where over 90% of natural gas demand growth is expected to take place. This point is well demonstrated by the growth in natural gas projects in our backlog. With that overview, I'll turn it over to Kim.

Okay. Thanks, Steve. So let's start with the natural gas business unit as usual. Here, transport volumes increased by about 3% for the quarter versus the first quarter of 2022. That was driven by EPNG Line 2000 return to service in mid-February, a 10% increase in deliveries to power plants as a result of colder weather in the top left, coal retirement, and low gas prices. The increases were offset by reduced LNG volume attributable to the Freeport outage, decreased export to Mexico, and reduced HDDs in Texas, Midwest, and the East. Natural gas gathering volumes were up 18% in the quarter compared to the first quarter of 2022, driven by a 42% increase in Haynesville volumes and a 21% increase in Eagle Ford volumes. Sequentially, total gathering volumes were up 4%. In our products pipeline segment, refined products volumes were flat for the quarter versus the first quarter of 2022, roughly in line with EIA, although there’s some variability in the components. Road fuels were down 3%, but we saw a 12% increase in jet fuel as international travel increased. Crude and condensate volumes were down 5% in the quarter versus the first quarter of 2022, driven by lower HH volumes as a result of unfavorable locational basis differentials coming out of the Bakken. Sequentially, volumes were up 1%. In our Terminals business segment, our liquids lease capacity remains high at 93%. Excluding tanks out of service for required inspection, approximately 96% of our capacity is leased. From a market perspective, there have been some nice improvements in our major liquids markets. In the New York Harbor, our Carteret Terminal is effectively 98% leased and had the strongest Q1 throughput since Q1 of 2019. In the Houston Ship Channel, we're effectively 100% leased, and rates have firmed up, and the Jones Act market continues to strengthen. On the bulk side, overall volumes were up 3%, due to increased volumes in pet coke, coal, steel, and grain. In the CO2 segment, prices were flat to down, depending on the commodity. On volumes, the CO2 volumes were down about 3%. With respect to oil volume, during the quarter, we had an outage at SACROC, which is our largest field and accounts for roughly two-thirds of our net production. The field was down completely for 10 days in late January, early February, and it took another seven days to ramp up to full production, which impacted both our oil and NGL volumes. It's hard to recreate what would have happened if we didn't have the outage, but our very rough estimate is that overall net oil production would have been up 6% or better comparing the first quarter of 2023 to the first quarter of 2022 as opposed to being down 2%, and NGL volume would have been up 1% versus being down 22%. These volumes would have added roughly $16 million or more to our segment results. Despite this outage, we still expect overall net oil volumes to be on budget for the year. And with that, I'll turn it over to David Michels.

Okay. Thank you, Kim. So for the first quarter of 2023, we're declaring a dividend of $0.2825 per share, which is $1.13 per share annualized, up 2% from the 2022 dividend. I'll start with a few highlights. We ended the first quarter of 2023 with net debt to adjusted EBITDA of 4.1 times, which leaves us with a good amount of capacity under our leverage target of around 4.5 times. We ended the quarter with over $400 million of cash on hand and nothing drawn on our $4 billion revolver capacity. We also issued $1.5 billion of bonds during the quarter, which addresses the majority of our funding needs for the rest of the year at favorable rates. We repurchased 6.8 million shares at an average price of $16.62 per share, and we entered into additional short-term interest rate locks. We have now eliminated short-term interest rate exposure on about half of our floating rate debt through 2023. That helps protect us from further interest rate pressure, and the locks have an average rate slightly better than our budget. Our balance sheet and liquidity are strong, and we continue to create value for our shareholders in multiple ways. For the full year, we are leaving our 2023 budget guidance in place. It's still early in the year, and a lot could change. We are facing pressure from commodity prices, as prices both realized to date and in the forward curves are below our budgeted prices. However, our forecast shows that pressure being substantially offset by better-than-expected operational performance, particularly in our natural gas and terminals business units. Before going on to the quarterly performance, you will notice that our financial disclosure has been updated. We believe this updated disclosure is more aligned with recent SEC guidance, particularly related to non-GAAP disclosures. Now on to the quarterly performance, we generated revenue of $3.9 billion, which is down $405 million from the first quarter of 2022. Our cost of sales was down $679 million to $1.2 billion. As expected, interest expense was up versus 2022. We generated net income of $679 million, up 2% from the first quarter of last year. Adjusted earnings, which exclude certain items, was $675 million, down 8% compared to the first quarter of 2022. On our business unit performance, our business segments were up 3% from the first quarter of 2022 in total, and our Natural Gas and Terminals segments were up while our products and CO2 segments were down. Our Natural Gas segment was up, with the largest drivers coming from greater sales margin on our Texas intrastate system and favorable rates on our recontracting at Midcontinent Express Pipeline. Our Product Pipeline segment was down mostly due to favorable first quarter 2022 commodity prices, which benefited our transmix businesses. Our Terminals segment was up mainly due to rate escalations and stronger volumes in our bulk terminals businesses, while our CO2 segment was down due to lower NGL prices and volume, lower oil volume, and higher pipeline integrity costs. Our G&A and interest expenses were higher versus the first quarter of last year. Additionally, in the first quarter, we had sustaining capital higher versus last year. We budgeted to have higher sustaining capital for 2023 versus 2022. Currently, we're forecasting sustaining capital to be only slightly higher than budget for the full year. Also, some of the quarter-over-last-year variance is due to some spending being accelerated into the first quarter. Our adjusted EBITDA was $1.996 billion for the quarter, up 1% from last year. Our DCF was $1.374 billion, down 6% from last year, and our DCF per share was $0.61, down 5% from last year. Moving on to our balance sheet. We ended the first quarter with $30.900 billion of net debt, and our 4.1 times ratio is the same as it was at year-end 2022. Our net debt decreased by $52 million over the quarter. Here is a high-level reconciliation of that change. We generated $1.333 billion of cash flow from operations. We paid out approximately $625 million in dividends. We spent approximately $550 million in total capital, which includes both growth and sustaining capital as well as contributions to our joint ventures, and we spent $113 million on stock repurchases. That brings you close to the $52 million change for net debt. Finally, I'd like to remind our research analysts that we provide a quarterly breakdown of our annual budget on several metrics, EPS, EBITDA, and DCF. We do that since our expected yearly results are not evenly distributed. The main driver of that is our seasonality in our natural gas pipeline business, which typically generates greater margin in our first and fourth quarters due to strong winter demand resulting in higher rates and capacity utilization. Additionally, we usually have greater expenses in the second quarter due to estimated tax payments. For example, we disclosed that our budgeted DCF for the first quarter was approximately $1.4 billion, while our budgeted DCF for the second quarter was approximately $1.0 billion reflecting that expected seasonality. Our actual DCF for the first quarter was $1.374 billion, a little lower than our budget, partially due to that accelerated sustaining capital spending. At this point, there are a number of analysts' estimates that appear to be out of line with this quarterly guidance, so we encourage you to revisit that guidance as necessary. With that, I'll turn it back to Steve.

Okay. Ted, we'll open it up to questions now. In addition to the people you've heard from so far, we've got a good portion of our management team around the table here, and we'll try to make sure you get an opportunity to hear from them on the questions you have about their businesses. So Ted, let's open it up.

The first question in the queue is from Brian Reynolds with UBS. Your line is open.

Hi, good afternoon, everyone. Maybe to start off on the EBITDA guidance. You talked about the base natural gas business perhaps outperforming slightly during the quarter, which is offset by the crude and natural gas deck and slightly lower product and terminal volumes. So I guess, perhaps on a forward-looking basis relative to the original guide in January, could you provide some puts and takes on a go-forward basis as the base natural gas business perhaps outperforms while the commodity deck and then product volumes relative to the January guide and PHP delay partially offset? Thanks.

Yes. The main point is that commodity prices are putting pressure on our CO2 business and somewhat on our natural gas business. However, these challenges are mostly being counterbalanced by the items discussed, which have helped our operational performance so far this year. A significant portion of this positive performance is coming from our natural gas business, especially in intra-state operations, along with higher sales values and capacity across our system. Additionally, we're experiencing greater terminal rate increases than we originally budgeted.

Great. Thanks. And maybe as a follow-up on growth CapEx, PHP delayed a few months, and then you have a TGP East 300 projects and the Tennessee Valley Authority projects coming into the backlog apparently. Is there any upward pressure on CapEx this year, or could some of that get pushed into next? Thanks.

Yes. Look, there's some upward pressure on CapEx, but it's not material to the overall investments that we're making this year. Really what we're seeing is there's been a slight uptick in our discretionary capital expenditures for the year, but that's largely due to new opportunities that have emerged over the course of the year. And look, we've been managing this since we started seeing inflation crop up over the course of 2022. We continue to do that and continue to examine our assumptions. When we sanction new projects, we're always making sure that our cost and schedule estimates are up to date. We're monitoring on a routine basis, the lead times for various key components, et cetera. Overall, like I said in my remarks, I think we're expecting to do very well on the capital that we're putting to work.

Great. Appreciate it. I'll leave it there. Have a great rest of the evening.

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

Hi, good afternoon.

Good afternoon.

Just wanted to follow up on the last point, I guess, as it relates to operational performance in the quarter versus budget. I noted that Texas interstate is doing better than expected. Is that a function of just long-term contract renewals at better-than-expected rates, or were there marketing opportunities that are spread based? Just trying to get a bit more color on the drivers there and the durability of those trends.

Yes, I mean, it's really kind of across the board. It's on contract renewals, it's on short-term business that we're doing, and it's on rates that we're getting for new business as well. Sital, do you have any other comments there?

Improved storage values are a significant factor.

Got it, that's very helpful there. And then just kind of shifting to the Permian as a whole. Natural gas egress, we've seen volatility in Waha prices, and with PHP being pushed off a little bit here, I would imagine that would persist across the year. Just wondering your thoughts, I guess, for egress and when the next pipe of the Permian could be needed in Kinder could participate in that type of project. Just wondering about updated Permian natural gas egress thoughts on their side?

Yes. Of course, you're right, and Waha has faced some pressure as a result, and there's been a combination of just continued growth in production. Also, there's been some maintenance, which used to be sort of back page gas daily kind of thing, but now it's sort of front page of mainstream media. But there’s that, there’s the growth in the underlying business, and clearly, we need additional expansion capability out of there. PHP provides that on a pretty quick basis. We are seeing a small delay, but that was a fast capacity addition that we're doing largely with compression and just a tiny bit of pipe out there. In terms of the longer term project egress, there are some on the boards right now. We continue to evaluate long-haul pipe expansion, but we're not making any real commitments or updates on that. We'll continue to talk with customers. We believe it will be needed, but probably in the 2026 to 2027 timeframe. So we'll continue to work on it.

2026, 2027 in service or when a new pipe would start construction?

In service.

That's very helpful. Thank you.

The next question in the queue is from Colton Bean with Tudor, Pickering, Holt. Your line is open.

Good afternoon. Maybe just sticking on PHP, it looks like the one to two-month delay there versus initial expectations November 1st. So, first, any detail on which components are driving the shift? And then are those now in hand, or do we still need to see some supply chain improvement to hit the December in service?

I’m not sure about everything being in hand yet. Our compression provider has upstream suppliers for certain electrical equipment, which they have identified. They are receiving it, but there have been delays. This is why we noted a delay. We are still committed to completing this; however, the supply chain remains a bit tangled, and that’s the situation we’re facing.

Okay. So based on everything you're seeing today, it still seems like sometime before year-end?

Yes. Yes.

Great. And then, David, you mentioned locking in roughly half the floating rate exposure through year-end 2023. I guess can you comment on where that stands for 2024 and more generally, do you have interest in locking in rates for next year, or contend to see how the market plays out for the time being?

Yeah, it's a good question. It is something we've taken a look at. We haven't locked anything in for next year yet. When we first started locking in interest rates for addressing some of our floating rate exposure, it was when interest rates were really low. So there was very little downside in doing it. We started doing it this year because there was some volatility that we forecasted for the year. We wanted to take some of the potential downside pressure off the table. It's still too early for us to weigh in on what that environment looks like next year, but we'll continue to keep an eye on it.

And the slots at expire?

Yeah, that's a good point, Kim. Kim reminded me that we have about $1.2 billion of our swaps portfolio maturing by the end of this year. So that's also something we'll consider when thinking about locking in future swaps.

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

Thanks. Hi, everyone. I wanted to ask about D3 RIN prices. They've come down quite a bit recently. I wonder if you can just remind us how this impacts the economics of your RNG projects?

Anthony Ashley?

Yeah, Michael, hi. What we've seen, I think, is a bit of a short-term phenomenon, which resulted from the EPA proposal that came out last November. They came out with proposed RVO targets, which were, I think, clearly, the market realizes were too low and so threw the market into excess supply. The current prices today, there's really no liquidity in. I don’t think there's necessarily any basis in those numbers. I think there's substantial evidence for the EPA when it comes out of its final ruling in June to increase those targets, and we fully expect RIN prices to recover in the second half of the year.

Just maybe two other points, Anthony. We're not a forced seller of D3 RINs, so we are not forced for funding or financing or other reasons to come out into this market at this point. The other point is we routinely stress-test our project returns to make sure there are still good returns under different RIN prices scenarios, and the projects and the investments that we've made in this sector still look good.

Okay. Thanks for all that. My second question, I want to talk about the balance sheet. Your leverage is at 4.1, and your budget for the year is 4.0. But your long-term target is 4.5. Any thoughts about reducing that leverage target over time, or should we expect that leverage will go back to that 4.5 times level over time? And if it does, what would get you there? Thanks.

Yeah, it's a good question, Michael. So no, we don't anticipate changing our long-term leverage target of around 4.5 times. We have been operating below it; we think that's prudent. It provides us with some cushion should we encounter any headwinds or see favorable opportunities to take advantage of, we could utilize some of that capacity. I think we would just have to wait and see what those look like. I don't think you have any particular ones on our table right now, but we will be disciplined with the utilization of that capacity because we do like having some of that cushion available to us.

The next question in the queue is from Neal Dingmann with Truist Securities. Your line is open.

Afternoon, guys. My question is about natural gas storage. I'm just wondering how you all view the natural gas storage opportunities, given that the time spread reflects heavy contango right now. I'm curious how much of a spread could you possibly capture and if there are a lot of growth opportunities around that?

Yeah, so Neal, we've flipped from a backward-dated curve to a contango curve. We see the supply and demand fundamentals moving in a positive direction. When you take a step back and look at storage, we’re seeing volatility across the network. I think the value in terms of what we can get to is new build, right, the new build mark. We've been renewing storage at the $3 mark as of late and probably north of that. As we move forward, we continue to see longer-term renewals as well as higher-priced renewals.

Got it. Okay. And then just lastly, regarding RNG, just wondering again if you could address that market overall. It seems that we haven't heard as much recently from you all or on other opportunities that you might be seeing just on the horizon there?

Anthony?

Yeah. I think where we are today is primarily focusing on building out projects that we have in place, which we effectively acquired with the three acquisitions we've done over the last couple of years. On an M&A front, it has become a little bit more of a frothy market for us, so our focus has been building out the projects we have and future organic growth there.

Very good. Thank you.

The next question is from Jean Ann Salisbury with Bernstein. Your line is open.

Hi. Good afternoon. Can you talk about the current backlog with a better multiple expectation at 3.5, obviously, than your historical average? Does that reflect a raising of the bar generally, or is it specific to a couple of brownfield projects, big-ticket items in the current backlog? Should I not read into it too much for the long term?

Yeah. It's not really a raising of the bar. We've had a hurdle rate that we've talked about before of about 15% that turns out to be a starting point. If there's a project with long-term contracts, secure cash flows, and very consistent cash flows, we flex off of that, which we do on bigger projects. That gets you to understand why you're seeing a difference in the multiple. The bigger, long-haul projects and investments tend to be done in an environment where there are others competing for that, and we end up with a good return but a bit of a higher multiple of EBITDA. So I think GCX, PHP, and Alba are examples where we’ve had our hurdle rate in place. There have been more of those in the mix historically when we've been showing you guys 6x EBITDA multiples on our projects. A lot of these projects are high-return build-offs of the existing network at very attractive returns, so the EBITDA multiple is a lot lower as a result. It's more a function of the composition of long haul and short haul than a raising of the barriers.

Great. That makes sense. And then after Winter Storm Yuri, as you guys kind of talked about, there should have been a willingness to pay more for gas pipelines and storage in Texas as a form of insurance, and it looks like that's been flowing through. My question is, there's been some talk about this Texas energy insurance program, the thing about building out all of these insurance gas power plants for spare capacity. Would you view that as a positive or negative for Kinder Morgan if it does go through, in a way, I suppose, it's sort of competing for insurance with your storage and pipeline capacity?

Not really competing with it. It would be a customer for it. Look, we'll break it into two here. One is, whether or not it’s good public policy, and I'll refrain from commenting on that. But the other is, if they build new gas-fired capacity in Texas to improve reliability in the electric grid, that's a good thing for gas companies in Texas. But you could have a long debate, and there is a long debate happening in Austin on whether you ought to just simply let the people who already build those things — who have been building them, at least along our footprint — continue to build them as opposed to having the state build them or incentivizing their building, I guess.

Okay. Thank you. That’s all for me.

Next question is from Spiro Dounis with Citi. Your line is open.

Thanks, operator. Afternoon, guys. Kim, first one for you. I think you had mentioned lower natural gas prices as a positive factor in attracting back some demand from power and industrial customers. Curious if you think we've seen a lot of that demand elasticity sort of snap back and play out at this point, or do you think there's a lot of latent capacity in the system that maybe hasn't reacted to lower prices yet?

In terms of the power demand, well, I'd say the power demand we saw in the first quarter was up 10% versus the first quarter of 2022. We saw nice increases in power demand. But we didn't have a winter in the center of the country all the way East, really. Had we had more HDDs during the winter, I think that power demand could have been higher than what we saw, and therefore, the gas that we moved to those power plants would have been higher.

Got it. Okay. That's helpful. Second question, also on natural gas prices. I'm curious to get your thinking on the trajectory of nat gas prices from here. As we look out beyond 2024 to 2025, you see a lot of LNG capacity coming, which should be supportive, but there is an expectation that supply could push prices down further. Given that you are close to your customers, I’m curious what you're hearing and how you expect producers to react if we do see prices fall maybe below $2?

Sure. With respect to the associated gas, obviously, we don’t expect much impact there. We've had a lot of discussions with our producers; in some of the dry gas basins, the breakeven there is pretty low, is what I would say. There’s always the potential that it could go lower, but we think, as you said, as the LNG demand comes on in 2024 and 2025, that those prices improve. As we've talked to our producers in the Haynesville and the Eagle Ford, we've seen some pullback from the small and medium-sized producers; the larger producers are continuing to produce. Looking at our outlook on our gathering volumes for the year, we're within 2% of our budget, and part of the reason that we're off our budget has nothing to do with prices. That’s really due to the delay in a project. So that's kind of what we're seeing.

Got it. Appreciate all the color. That's all I had. Thanks, guys.

And the next question is from Sunil Sibal with Seaport Global Securities. Your line is open.

Yes. Hi. Good afternoon, everybody. I wanted to flush the natural gas long-haul pipeline capacity in the Permian a little bit. It seems like when you look at the volatility in Waha prices, it seems to have gone up over the last few months despite the fact that EPNG outage has been restored. Could you talk about the nature of your conversations with customers regarding building new capacity there? What are the major sticking points before a big project could go ahead?

When we consider the Waha situation, it's evident that with the increasing LNG demand over the long term, there will be a need to address the basis differential. Commercialization is essential for this process. We have been engaging with customers about potentially adding a third pipeline out of the basin, and the direction it takes will ultimately depend on market requirements and which LNG facility moves forward with a final investment decision next. We are actively discussing both supply and market aspects to bridge the gap. Ultimately, it comes down to the timing from the market and the need to achieve an appropriate rate of return from our perspective.

Got it. Thanks for that.

At this time, I'm showing no further questions.

Okay. Well, thank you very much for joining us today, and have a good evening.

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