Welcome to the Quarterly Earnings Conference Call. [Operator Instructions]. 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.

Richard Kinder — Executive Chairman

Thank you, Ted. And as usual, before we begin, I would 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. And just this week, our Assistant Secretary of Energy stated that given the current state of events, and I quote, “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. In my judgment, 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.

Steven Kean — Chief Executive Officer

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 of projects are added [Phonetic] attractive returns in aggregate, well above our cost of capital. At Investor Day, every year, starting with the 2015 to 2017 period, we have been showing 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 a challenge 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 3.5 times.

Third, on renewals, we showed at the beginning of the year how our base business renewals in the 2023 budget are showing more increases than 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 this is 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 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 citing 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.

And with that overview, I’ll turn it over to Kim.

Kimberly Allen Dang — President

Okay. Thanks, Steve. So let me 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’s Line 2000 return to service in mid-February, a 10% increase in deliveries to power plants as a result of colder weather in the Southwest, coal retirement and low gas prices. The increases were offset by reduced LNG volume that was 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; and that was 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 that was roughly in line with EIA, although there is some variability in the components. Road fuels were down 3%, but we saw a 12% increase in jet fuel as international travel increased. Our crude and condensate volumes were down 5% in the quarter versus the first quarter of 2022 and that was 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 were required inspection, approximately 96% of our capacity is leased. From a market perspective, there has 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%, and that was 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 then 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 to the first quarter — comparing to the first quarter of ’23 to the first quarter of ’22 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.

David Michels — Vice President and Chief Financial Officer

Okay. Thank you, Kim. So for the first quarter of 2023, we are 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 as well as 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 disclosure.

Now on to the quarterly performance, we generated revenue of $3.9 billion, which is down $405 million from the first quarter of ’22. 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 excludes 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 ’22 in total, and our Natural Gas and Terminals segments were up and 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 Mid-Continent 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, and 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. And additionally, in the first quarter, we had sustaining capital higher versus last year. We budgeted to have higher sustaining capital for 2023 versus 2022, and currently we’re forecasting sustaining capital to be only slightly higher than budget for the full-year. But, we also had — but also some of the quarter over last year quarter variance is due to some spend being accelerated into the first quarter. So 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 $52 million over the quarter, and here is a high-level reconciliation of that change. We generated $1.333 billion of cash flow from operations, we paid out $625 million approximately in dividends, we spent approximately $550 million in total capital, and that includes both growth and sustaining capital as well as contributions to our joint ventures, and we spent $113 million on stock repurchases. And that gets 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. And we do that since our expected yearly results are not evenly distributed. The main driver of that is our seasonality in our natural gas and pipelines business, which typically generate greater margin on our first and fourth quarters due to strong winter demand resulting in higher rates and capacity utilization. Additionally, we have — we usually have greater expenses in the second quarter due to estimated tax payments. So 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 capital, sustaining capital spending. And at this point, there are a number of analyst’s estimates that appear to be out-of-line with this quarterly guidance. So we encourage you to revisit that guidance as necessary.

And with that, I’ll turn it back to Steve.

Steven Kean — Chief Executive Officer

Okay. Ted, we’ll open it up to questions now. And, I’ll just point out that 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.

Question & Answers

Operator

All right. [Operator Instructions]. First question in the queue is from Brian Reynolds with UBS. Your line is open.

Brian Reynolds — UBS — Analyst

Hi. Good afternoon, everyone. Maybe to start off on the EBITDA guidance. You talked about the base nat gas business perhaps outperforming slightly during the quarter, which is offset by the crude and nat gas deck and slightly lower product and terminals 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 nat gas business perhaps outperforms while the commodity deck and then product volumes relative to the January guide and PHP delay, partially offset?

David Michels — Vice President and Chief Financial Officer

Yeah. I think that’s, I think the bottom-line summary is commodity prices are pressuring our business in the CO2 business and a little bit in our natural gas business, and those are being largely offset with some of the items that you talked about largely offset so far for the year so that, that business operational performance, outperformance is offsetting that commodity price weakness. And a lot of that is coming in our natural gas business, particularly in intra-states and in products [Phonetic] and higher commodity price, higher capacity sales values across our system in the natural gas business, we’re also seeing higher terminals, rate escalations than what we had budgeted.

Brian Reynolds — UBS — Analyst

Great. Thanks. And maybe as a follow-up on growth capex, PHP is 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.

Steven Kean — Chief Executive Officer

Yeah. Look, there is some upward pressure on capex, but it’s not — I don’t think material to the overall investments that we’re making in this year. Really what we’re seeing is there’s been a slight uptick in our capital expenditures, 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. And 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, etc. And so 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.

Brian Reynolds — UBS — Analyst

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

Operator

Next question in the queue is from Jeremy Tonet with J.P. Morgan. Your line is open

Jeremy Tonet — J.P. Morgan — Analyst

Hi, good afternoon.

Steven Kean — Chief Executive Officer

Good afternoon.

Jeremy Tonet — J.P. Morgan — Analyst

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

Steven Kean — Chief Executive Officer

Yeah. 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?

Sital Mody — President, Natural Gas Pipelines

Yeah. I mean, I really — and also, improve storage value. Yeah, a big piece.

Jeremy Tonet — J.P. Morgan — Analyst

Got it. That’s very helpful there. And then just kind of shifting to the Permian as a whole. Natural gas egress [Phonetic], 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, if — how Kinder could participate in that type of project. Just wondering an updated Permian natural gas egress thoughts on their side?

Steven Kean — Chief Executive Officer

Yeah. Well, 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 has 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 is that, there is the growth in the underlying business. And so 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 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 — Sital, the 20?

Sital Mody — President, Natural Gas Pipelines

’26-’27.

Steven Kean — Chief Executive Officer

’26-’27 time frame. So we’ll continue to work on it.

Jeremy Tonet — J.P. Morgan — Analyst

’26-’27 in service, or when a new pipe would start construction?

Sital Mody — President, Natural Gas Pipelines

In service.

Jeremy Tonet — J.P. Morgan — Analyst

That’s very helpful. Thank you.

Operator

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

Colton Bean — Tudor, Pickering, Holt & Co. — Analyst

Good afternoon. So maybe just sticking on PHP, it looks like the one to two-month delay there versus initial expectations November 1. As 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?

Steven Kean — Chief Executive Officer

Well, I don’t know about in hand, so this is our provider of the compression and they have upstream providers of certain — really, it’s electrical equipment. And they have that identified. They’re getting it, but it’s been delayed. And so that’s why we’ve reflected a delay. We’re still going to get this thing done. It’s just — the supply chain is still a little bit tangled and that’s what we’re seeing there.

Colton Bean — Tudor, Pickering, Holt & Co. — Analyst

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

Steven Kean — Chief Executive Officer

Yes.

David Michels — Vice President and Chief Financial Officer

Yes.

Steven Kean — Chief Executive Officer

Yes.

Colton Bean — Tudor, Pickering, Holt & Co. — Analyst

Great. And then, David, you mentioned locking in roughly half the floating rate exposure through year-end ’23. 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?

David Michels — Vice President and Chief Financial Officer

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 — to address some of our floating rate exposure, it was when interest rates were really, 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. And so, we wanted to take some of the potential downside pressure off the table. 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.

Kimberly Allen Dang — President

And the slots at expire?

David Michels — Vice President and Chief Financial Officer

And we do — yeah, we do have some — that’s a good point, Kim. Kim reminded me that we do have some of the swaps about, I think it’s $1.2 billion of our swaps portfolio mature by the end of the year this year. So that’s also a component that we’re going to take into account when we’re thinking about locking in future swaps.

Operator

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

Michael Blum — Wells Fargo — Analyst

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?

Steven Kean — Chief Executive Officer

Yes. Anthony Ashley.

Anthony Ashley — President, CO2 and Energy Transition Ventures

Yes, Michael. Hi. Yeah, so what we’ve seen, I think, is a bit of a short-term phenomenon with — and it kind of resulted out of 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 through the market into excess supply. The current prices today, there’s really no liquidity in. So I don’t think there’s necessarily any basis in those numbers. I think there is a 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.

Steven Kean — Chief Executive Officer

And just maybe two other points, Anthony, we’re not a forced seller of D3 RINs, so we don’t — we’re not forced for funding or financing or other reasons to come out into this market at this point.

And then the other point is, we do this routinely, but we look to stress test our project returns to make sure there is still good returns under different RINs pricing scenarios and the projects and the investments that we’ve made in this sector still look good.

Michael Blum — Wells Fargo — Analyst

Okay. Thanks for all that. My second question, I want to ask is [Phonetic] about the balance sheet. So, your leverage is 4.1, your budget for the year is 4.0, but your long-term target is 4.5, any thoughts to reduce that reduce that 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.

David Michels — Vice President and Chief Financial Officer

Yeah. It’s a good question, Michael. So no, we don’t have an anticipation of changing our long-term leverage target of around 4.5 times. We have been operating below it, and we think that’s prudent. It can give us some cushion, should we have any headwinds, or should we see favorable opportunities out there to take advantage of, we could utilize some of that capacity to take advantage of those opportunities.

I think we would just have to wait and see what those look like. I don’t think we have any particular ones on our table right now. But I think, we would say that, we would be disappointed with the utilization of that capacity, because we do like having some of that cushion available to us.

Michael Blum — Wells Fargo — Analyst

Thank you.

Operator

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

Neal Dingmann — Truist Securities — Analyst

Afternoon, guys. My question is natural gas storage. I’m just wondering — I’m wondering how you all view the natural gas storage opportunities given out there, obviously, the time spread reflects pretty heavy contango right now. So I’m just wondering maybe how much of a spread could you possibly capture? And I was just curious, if there is a lot of growth opportunities around that?

Steven Kean — Chief Executive Officer

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. And so when you just 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 $3 mark, as of late, and probably north of that. And so, I think, as we move forward, we continue to see longer-term renewals as well as higher-priced renewals.

Neal Dingmann — Truist Securities — Analyst

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

Steven Kean — Chief Executive Officer

Anthony?

Anthony Ashley — President, CO2 and Energy Transition Ventures

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

Neal Dingmann — Truist Securities — Analyst

Very good. Thank you.

Operator

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

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Hi. Good afternoon. Can you talk about the current backlog with a better multiple expectation at 3.5, obviously, then kind of 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 and the current backlog, and I shouldn’t read into it too much for the long-term?

Steven Kean — Chief Executive Officer

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 kind of a starting point, if there is 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; and then, that gets you to why you’re seeing a difference in the multiple. The bigger long-haul projects and the bigger investments they tend to be done in an environment where there are others who are competing for that, and we end up with a good return, but a bit of a higher multiple of EBITDA. So think GCX, PHP, think of Elba as an example, over this period of time that we’re talking about where we’ve had our hurdle rate in place.

And so, there have been more of those in the mix historically when we’ve been kind of showing you guys six times EBITDA multiples on our projects, when we do our annual update at the investor conference. And now, a lot of these projects are high-return build-offs of existing — the existing network at very attractive returns. And so the multiple ends up being a lot more attractive, the EBITDA multiple is a lot lower as a result. So not a function of hurdle rate, more a function of the composition of long haul and short haul card [Phonetic].

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Great. That makes sense. And then after Winter Storm Yuri, as you guys kind of talked about, there should have been kind of 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. I guess, my question is, there has 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?

Steven Kean — Chief Executive Officer

Not really competing with it. It would be a customer for it. And so, look, we’ll break it into two here. One is, whether or not its good public policy, and I’ll refrain from commenting on that. But the other is, if they build new gas-fired capacity in the state of 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 and have been building them, at least along our footprint to continue to build them as opposed to having the state build them, or incent their building I guess.

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Okay. Thank you. That’s all for me.

Operator

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

Spiro Dounis — Citi — Analyst

Thanks, operator. Afternoon, guys. Kim, first one is 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 maybe 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?

Kimberly Allen Dang — President

In terms of the power demand, well, I would say the power demand we saw in the first quarter was up 10% versus the first quarter of ’22, so we saw nice increases in power demand. But we didn’t have a winner in the center of the country all the way East really. And so, 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.

Spiro Dounis — Citi — Analyst

Got it. Okay. That’s helpful. Second question, also on natural gas prices. And if I could, maybe just curious to get your all thinking on the trajectory of nat gas prices from here. And I guess as we look out beyond ’24 and ’25, you see a lot of LNG capacity coming, which should be supportive. But I think between now and then, there is an expectation here that supply could push prices down further. And just given you guys are close to your customers, just curious kind of what you’re hearing and maybe how you’d expect producers to react, if we do see prices fall maybe below $2?

Kimberly Allen Dang — President

Sure. So with respect to the associated gas, obviously, 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 are pretty low, is what I would say. There is always the potential that it could go lower, but we think, again as you said, as the LNG demand comes on in ’24 and ’25, does 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, list of the larger producers are continuing to produce and as we look at our outlook on our gathering volumes for the year, we’re within 2% of our budget — the 2% off of our budget. And part of the reason that we’re off of our budget has nothing to do with prices that really has to do with the delay in a project, so that’s kind of what we’re seeing.

Spiro Dounis — Citi — Analyst

Got it. Appreciate all that color. That’s all I had. Thanks guys.

Operator

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

Sunil Sibal — Seaport Global Securities LLC — Analyst

Yes. Hi. Good afternoon, everybody. So I just wanted to flush the natural gas long-haul pipeline capacity in 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. So I was just curious if you could talk a little bit about, the nature of your conversations with the customers with regard to building new capacity there? What are the major kind of sticking points before a big project could go ahead?

Steven Kean — Chief Executive Officer

So yeah, I mean, look, when we’re taking, we look at the Waha, there is clearly — as you look out long-term with all the LNG demand coming on, there is going to be basis differential that needs to be solved for, really what’s going to take, what this is going to take is commercialization. And as you know, we’ve been talking with customers about a third pipe out of the basin, where that gets pointed ultimately depends on the market need and which LNG facility gets FID next. But we have been having discussions on both sides with the supply side and the market side, trying to bridge the gap. And I think really, ultimately, it comes down to timing from the market side as well as commercializing an appropriate rate of return from our perspective.

Sunil Sibal — Seaport Global Securities LLC — Analyst

Got it. Thanks for that.

Operator

And at this time, I’m showing no further questions.

Richard Kinder — Executive Chairman

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

Operator

[Operator Closing Remarks]

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KINDER MORGAN INC

Q1 2023

Earnings Transcript

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