Welcome to the Quarterly Earnings Conference Call. Today’s call is being recorded. If you have any objections, please disconnect at this time. I will now turn the call over to Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Ted. And before we begin, as we always do, 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 that are 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. An analyst recently described Kinder Morgan as a capital-efficient business model leveraged to natural gas infrastructure growth. I largely agree with that assessment, although it omits our significant steps in our energy transition efforts, including renewable natural gas, renewable diesel, and potentially carbon capture and sequestration. I spent the last several quarters on this call describing that capital-efficient business model. And today, I want to spend a bit of time discussing natural gas infrastructure and the value of our existing infrastructure in today’s environment. As we all know, it’s become increasingly difficult to build new greenfield pipeline projects, particularly in the Northeast and other areas outside the U.S. Gulf Coast. While this situation is, in my opinion, unfortunate and poor public policy, it does make existing infrastructure even more valuable. I don’t think that value is fully recognized by the equity markets. The difficulty in building new pipeline and ancillary facilities widens the moat to use long bucket sprays around existing assets at a company like KMI. That’s an obvious source of additional value. But beyond that, having such an extensive network already in place affords great opportunity for a company like ours to extend and expand our assets on an incremental basis without the Herculean task of permitting and building a new greenfield project. Those step-out projects can provide great service to our customers and yield a very good return for our shareholders. We are fortunate at KMI that a large portion of our network is in Texas and Louisiana, states that understand and appreciate the need for new energy infrastructure and where so much of the demand for additional throughput, particularly natural gas, is located. Let me be more specific. The demand for natural gas in those states is projected to grow enormously over the rest of this decade. That growth is driven by a number of end-users, but let me just focus on LNG export facilities. Year-to-date, in 2022, LNG is consuming over 11 Bcf a day, and that number incorporates the absence of roughly 2 Bcf a day of demand from the Freeport facility, which has been shut down since June. According to the S&P Global LNG forecast, that number is predicted to grow to 22 Bcf a day by 2027 as new facilities come online. That’s virtually doubling the current demand, which has already grown by 400% in the last 5 years. We project that after 2027, LNG demand will continue to grow and be expected to be 28 Bcf a day by 2030. Given the situation in Europe today, which will result in more long-term contracts and the continuing usage in Asia, this hyper-growth scenario actually seems pretty reasonable to me. That’s a huge increase and most of it will occur in Texas and Louisiana, where so much of our asset base is located. That is what we, in the pipeline business, call demand pull, which in many respects is more valuable than supply push. As you know, we currently move about 50% of all the gas consumed by LNG facilities, and we expect to maintain or expand that share in the future. To serve our customers, both producers and end-users, we are continuously expanding our system on an incremental basis to accommodate the growth we expect. Just a couple of examples of that effort include the expansion of our PHP system that connects the Permian basin, the Gulf Coast, and the building of the Evangeline Pass system to serve the venture capital LNG facility in Plaquemine, Paris, Louisiana, and we expect to announce additional projects in the coming months. When you add the increasing need for natural gas for industrial uses, electric generation, and exports to Mexico to that massive LNG demand, the result is an enormous opportunity to grow our system in a capital-efficient manner, which in turn will grow the value of our company.

Yes. Thanks, Rich. We are having a good year. We are projecting to be nicely above plan for the year and substantially better year-over-year Q3 to Q3, as Kim and David will show you. Some of the outperformance is commodity price tailwinds, but we are also up on commercial and operational performance. Just a couple of highlights. Our capacity sales and renewals in our gas business are strong. Gathering and processing is also up versus plan and up year-over-year. Existing capacity is growing in value on our natural gas network. And we are seeing it across our network on our major interstate systems and on our Texas intrastate system, and we are seeing it in both storage and transportation service offerings. We are even seeing it on a previously challenged system, the Midcontinent Express Pipeline. In CO2, SACROC production is well above plan. And of course, we are benefiting from higher commodity prices in this segment, though prices are not as elevated as they were when we talked after Q2. We are facing cost headwinds, mostly because of added work this year. But while costs are up, we are actually doing very well in holding back the impacts of inflation. It’s hard to measure precisely, but based on our analysis of what we can reliably track, we are well below the headline PPI numbers that you are seeing. Actually, we appear to be experiencing about half of that increase. Much good work by our procurement and operations teams, and much of this good performance is attributable to our culture. We are frugal with our investors’ money. Looking ahead, we are seeing good opportunities across our network and in gas, in particular, Rich emphasized LNG, and that is clearly the biggest long-term opportunity, and our network is especially well positioned. I will give you an illustration of that. We currently have 5.7 Bcf a day under long-term contracts serving existing LNG facilities. The associated investment for that 5.7 Bcf was $1.3 billion. That is very capital-efficient expansion of our network. There are other opportunities as well. We have identified and talked to customers on our Texas Intrastate system about over a Bcf a day of power plant, industrial, and utility expansions. Of course, not all that’s going to happen, but it shows the level of economic activity in one of our biggest natural gas markets. We now have a backlog of $2.7 billion of projects; that’s up $600 million on a net basis since last quarter, meaning taking into account the projects that rolled into service over the quarter. Almost 80% of that backlog is in low-carbon investments, natural gas, energy transition ventures, and renewable diesel and renewable feedstocks projects in our products and terminals businesses. On Energy Transition Ventures, we expect with what we have already acquired and with the projects under construction or development right now to invest about $1.2 billion at an EBITDA multiple of a little over 5x when everything is up and running. I will add that while we have experienced some delay and modest cost increases in this business, the returns are very good, and the EBITDA multiple is strong. We also closed on the sale of an interest in our Elba Liquefaction facility during the quarter. The implied enterprise value to EBITDA multiple of the sale was approximately 13x. And so to think about in terms of use of proceeds, that can pay us very favorably to our expansion project multiple of 5.5x in aggregate over the last 3 years, as well as through our share price multiple. Again, we are having a very good year, and we are setting our business up well for the future. Our balance sheet is strong. We are seeing good value, particularly in natural gas and renewables. We are finding and executing on projects with attractive returns, and we are returning value to shareholders. And I will turn it over to Kim.

Okay. Thanks, Steve. Starting with the Natural Gas business segment, transport volumes were roughly flat for the quarter versus the second quarter of 2021, and we saw increased volumes from power demand, and that was offset by reduced volumes to Mexico as a result of third-party pipeline capacity added to the market, the pipeline outage on EPNG, the Freeport LNG outage, and continued decline in Rockies production. If you adjusted our volumes for the EPNG and Freeport outages, which are temporary in nature, we estimate volumes would have been up about 4%. Deliveries to LNG facilities off our pipe averaged about 5.2 million dekatherms per day. That’s about 1% higher than the third quarter of 2021, but it’s lower than the second quarter of this year. Again, that’s due to the Freeport LNG outage. Deliveries to power plants were robust in the quarter. They were up about 11%, driven by record summer power demand, that’s 880 million dekatherms per day of incremental gas moving to power plants. It’s pretty incredible. Our natural gas gathering volumes were up about 13% in the quarter compared to the third quarter of 2021, and that was driven by the Haynesville volumes, which were up about 70%. Sequentially, volumes are up 6% with big increases in the Bakken, up 14%; Haynesville, up 8%; and Eagle Ford, up 7%. Overall, our natural gas gathering volumes were budgeted to increase about 10% for the full year, and we are currently on track for about 13%. Overall demand for natural gas is very strong, as both Rich and Steve mentioned, driving the demand for our transport and storage services, and we expect that demand to continue to grow. To add on to what Rich and Steve said, our fundamentals group estimates natural gas demand to grow from roughly 100 Bcf a day market currently to approaching 130 Bcf market by 2031. So the world needs a reliable supplier of natural gas, and the United States is positioned to be that supplier. According to the EIA, we have 80 plus years of recoverable reserves. And from an environmental perspective, the U.S. is one of the lowest emission producers in the world. On the products segment, refined products volumes were down about 2% in the quarter versus the third quarter of 2021, slightly outperforming EIA, which was down 3%. Gasoline and diesel were down 3% and 5%, respectively. But we did see an 11% increase in jet fuel demand. For October, we started the month a little bit stronger than the Q3 results. On crude and condensate, volumes were down about 5% in the quarter. Sequentially, they were down 2% with a reduction in the Eagle Ford more than offsetting an increase in the Bakken. On the Terminals business segment, our liquids lease percentage remains high at 91%. If you exclude tanks out of service for required inspection, so that lease percentage is roughly 95%. Liquids throughput, which does not drive current results, but it’s an indicator of our ability to renew contracts in the future was up about 7%, driven by gasoline, diesel, and renewable volumes, which comprise over 85% of our liquids volume. We continue to experience some weakness in the New York Harbor, and our tankers business was hurt in the quarter by lower average rates, but that business has continued to improve. We currently have all 16 vessels sailing under firm contracts with average remaining terms of over 5 years. For 2023, we have approximately 90% of the vessel days under firm charter. And if you look at the shipper contractual options likely to be exercised, it’s 100% at average rates that are higher than 2022. We have also seen interest in chartering vessels several years out. On the bulk side, overall volumes were flat. Pet coke and coal were up nicely, but that was offset by lower steel; but from a margin perspective, the higher pet coke and coal substantially offset the lower steel. In the CO2 segment, metal production in the quarter was up 7% versus our budget. For the full year, we are expecting oil production to be about 4% above our budget, CO2 volumes to be about 8% of our budget, and price to exceed our budget. These positives are partially offset by higher operating expenses, and that’s due to a combination of higher activity level/production and inflation. For Q3 versus Q3 2021, crude production was down about 3%. CO2 sales volumes were down 11%, and that was driven by the expiration of a carried interest in the project. NGL volumes were up 1%, and prices were higher across the board. Overall, we had a very good quarter. DCF per share was up 7% versus our plan and up 8% year-to-date. We currently project that we will exceed our full-year guidance on DCF per share and EBITDA by 4% to 5%. Timing on sustaining CapEx into the fourth quarter out of the second and third is the primary driver of the DCF difference between the year-to-date performance and the expected full-year performance. As we progress through the year, we are seeing more high-return expansion opportunities. In the quarter, as Steve said, our backlog increased about $600 million. And as a result, going forward, we would expect to be in the middle of our $1 billion to $2 billion range or maybe at the higher end. And with that, I will turn it over to David Michels.

Thank you, Kim. So for the third quarter of 2022, we are declaring a dividend of $0.2775 per share, which is $1.11 annualized and 3% up from our 2021 dividend. One highlight before I start on the financial performance: We continue to take advantage of our low stock price by repurchasing shares this past quarter. We added over $90 million of repurchases to what we reported last quarter. Year-to-date, we have now repurchased approximately 21.7 million shares at an average price of $16.94 per share. We believe those share repurchases are going to generate an attractive return for our shareholders. Our savings from the current dividend alone, without regard to the terminal value or dividend growth, is 6.6%. For the financial performance for the quarter, we generated revenue of $5.2 billion, up $1.35 billion from the third quarter of 2021. The associated cost of sales also increased by $1.16 billion. So combining those two, our gross margin was $195 million higher. Our net income was $576 million, up 16% from $495 million in the third quarter of last year. Our adjusted earnings, which exclude certain items, was up 14% compared to the third quarter of last year. On a distributable cash flow basis, our performance was also very strong. The Natural Gas segment was up $69 million with greater volumes on our KinderHawk system, Haynesville, higher recontracting rates on MEP, NGPL, and SNG, greater contributions from our Texas Intrastate systems, and favorable commodity prices impacting Altamont and Copano South Texas. Our Product segment was down $23 million, driven by a decline in commodity prices impacting our inventory values, lower crude volumes on our HH system, as well as higher integrity costs, partially offset by higher rate escalations year-over-year. Our Terminal segment was up $7 million as Kim mentioned, greater coal and pet coke volumes partially offset by lower contributions from our New York Harbor and Houston Ship Channel liquids terminals versus the third quarter of last year. Our CO2 segment was up $41 million, driven mostly by favorable commodity prices. So our EBITDA of $1.773 billion was up 7% from last year, and our DCF was $1.122 billion, our DCF per share was $0.49, both 11% above last year. For the full year, as Kim mentioned, we expect to be 4% to 5% above our budget. And for the quarter, DCF was ahead of budget by 6.5%. Some of that is due to a shift of sustaining capital into the fourth quarter. And as a reminder, at our Investor Day presentation in January, we said about 22% of our DCF would come in the third quarter of this year. If you apply that 22% to our budgeted DCF increased by 5%, which is what we guided you to last quarter, you would see that we exceeded that expectation this quarter. So, a helpful reminder that we provide useful information on quarterly shaping at our Investor Day. Moving on to the balance sheet. We ended the third quarter with $31.2 billion of net debt and a net debt to adjusted EBITDA ratio of 4.2x. That’s up from 3.9x at the year-end as the non-recurring EBITDA contribution from the Winter Storm Uri in February 2021 was captured in that year-end ratio. The year-end ratio was 4.6x, excluding Uri EBITDA contribution. So we ended this quarter nicely favorable to the year-end metric excluding Uri. Our net debt decreased to $10 million or has decreased to $10 million year-to-date. So I’ll go through a high-level reconciliation of that. We’ve generated year-to-date DCF of $3.75 billion. We’ve paid dividends of $1.83 billion. We’ve contributed or repaid growth capital and contributed to joint ventures $700 million. We had $225 million of increased restricted deposits, which is mostly due to cash posted for margin related to our hedging activity. We’ve repurchased $331 million of stock through the third quarter end. We’ve had about $500 million of acquisitions, and that’s sort of the two renewable natural gas companies. We received approximately $560 million from the sale of our interest in Elba Liquefaction company, and we’ve had about $750 million of working capital use, which is primarily interest expense payments and some other legal and rate settlements. And that gets you close to the reconciliation for year-to-date change in net debt. So that completes the financial overview, and I’ll turn it back to Steve.

Alright. Ted, let’s go ahead and open up the channel for questions here and I’ll just remind everybody, limit yourself to one question and a follow-up. And then if you’ve got more, get back in the queue, and we will get to you and get your questions answered. And also, we have a good chunk of our management team sitting around the table here today, and I’ll make sure that you hear from them on questions about their businesses. Alright. Ted, with that, let’s take the first question.

First question in the queue is from Chase Mulvehill, Bank of America. Your line is now open.

Hey, good afternoon, everybody. I guess first thing I wanted to hit on is just kind of Permian residue gas egress. And you’ve got EPNG outage today. And I guess, maybe could you talk about the timing and how much incremental throughput you would see out of Line 2000 of basically EPNG system, which Line 2000 is back up and running.

Okay. Tom Martin?

Yes. So given the nature of that outage, we can’t say too much in detail. But just in general, we see somewhere between 500,000 and 700,000 a day of incremental volumes flowing west when that line is back in service.

Okay, perfect. And unrelated follow-up, I know it’s a little early to talk 2023. I know you’re not going to give us exact numbers or anything, but maybe just some puts and takes as you see the overall business as we kind of look out to 2023?

Yes. It is too early. We’re just in the middle of our annual budget process. And so we will – as we always do, we will give you an update when we’ve got that information complete. But I mean, I think it’s the things that we’ve talked about here today. It’s – we’ve got some nice tailwinds. Who knows what commodity prices are going to look like next year. But we have some nice tailwinds in our Natural Gas business and a good backlog of projects and good project opportunities. And so those are the pluses. On the minuses, we don’t know what’s going to happen with interest rates, but we do have about $7.5 billion of floating rate debt, and we have some renewals on – or some refinancings on about $3.2 billion, which is actually our highest year next year. We don’t see another year above $2.1 billion after that. And so those are some of the big puts and takes.

Okay, perfect. I will turn it back over. Thanks, Steve.

Next question is from Jeremy Tonet with JPMorgan. Your line is now open.

Hi, good afternoon.

Good afternoon.

Capital allocation is a big debate point in the market that folks are focused on, and just wondering if you could update us on how you see your capital allocation philosophy these days? On the one hand, there is a case to be made for repurchases, saw some in the quarter. But how do you weigh maybe ramping up the pace of buybacks relative to the other opportunities you have, especially with regards to RNG consolidation or other energy transition growth CapEx opportunities as you laid out there?

Yes. We look at all of those things. And of course, we’re kind of a broken record on this, but the first in the order of operations, making sure we’ve got a strong balance sheet, we do. And our metrics are proving to be stronger than the long-term approximately 4.5x. And so we’re in good shape there. Having – as David said, at the beginning of the year in the investor contract – conference, having a little extra capacity is a good thing, including for equity investors because it positions you well against the – for the pluses and also against the minuses. Then from there, we want to invest in attractive returning high NPV projects well above our cost of capital that we’re confident we can execute on well. And so that goes to what you see has happened in our backlog and the opportunities that Kim alluded to. And then from there, it’s returning value to shareholders, and that’s a combination of a growing, but well-covered dividend. So we’re up 3% of the dividend year-over-year, as David mentioned, and then opportunistic share repurchases, which we’ve done a significant amount of this year. And so that’s kind of the order of operations for how we think about capital allocation and all of it, keeping in mind bringing value to our investors.

Got it. Thank you for that. Very helpful. And just want to circle up with Elba real quick. Just wondering, could Elba be expanded and might you look to monetize more of that or similar assets in the future?

So yes, it can be expanded, and we are going through the evaluation process now, very early days looking at potentially a little over 5 million MTPA – 5 MTPA opportunity there, but again, very early days to know whether that will work, but we do have the space for it. And that would be synergistic with the existing tankage and dock usage there. And as far as selling incremental interest there, I mean, that would be on the existing cash flows, really, any expansion opportunity would be separate and apart from that.

Yes. And to be clear, I mean we like our position in Elba, where we got a very, very good – we made several very good deals at attractive multiples and actually have pulled in more proceeds than we’ve invested in the facility, and we still own 25% of it, and the expansion opportunity that Tom is referring to is outside of the JV. And so if we are able to – and we’re not – it’s not in our backlog, we’re not projecting that for you today, but we are examining the opportunity to do an expansion, which would be to our account.

Hi, good afternoon. So maybe just to start on the guidance language, you referenced trending 4% to 5% above budget for EBITDA. You obviously announced the Elba transaction; strip has come down a bit. But I wonder if you could talk about any other drivers around the subtle change in the language from last quarter?

Yes. Since the last quarter, we’ve seen significant outperformance in the gas group. We’ve got lower sustaining CapEx. On the other hand, as you noted, commodity prices have decreased. We’ve seen lower volumes in the Bakken, primarily because it took longer for them to recover from an April storm than we anticipated, lower refined products volumes, and higher interest.

Got it. That’s helpful. And then in the event of a potential product export ban, I wonder if you could just talk about how your assets would be positioned in that scenario, particularly thinking about storage, product pipes, and the Jones Act tankers business?

Yes. But we will start with terminals and also discuss products, John.

From a terminaling standpoint, we think it will be neutral for us. And on the negative side, we will see a decrease at our export docks. And we handle about 50 vessels a month there at about 43,000. So it’s roughly $2 million each month we will see degradation on. But on the positive side, you’ll see an increase in Jones Act volumes. You’ll see an increase in volumes of the Colonial and Explorer pipelines, which were the largest origin point. And you’ll see a spike in my opinion, in the price of storage, both in there and in New York Harbor.

And Dax from a products pipeline...

Yes, for us, it’s probably neutral to positive. I think the West Coast is probably reasonably neutral. But if you look at the Southeast, and you’ve got products that back up in PADD 3 and you’ve got to clear that out of there. We certainly have capacity on product Southeast pipeline. And I would expect that the products would move on that, particularly if Colonial moves in or continues to stay in allocation. We clearly have storage positions in the Southeast that I think to John’s point would benefit as well. And then probably a little bit less important, but on CFPL, I think that some of the imports that you’re seeing coming into Port Canaveral that get trucked into Central Florida would probably get backed off, and we could see some benefit on CFPL as well, so.

And Marc, just to comment on probability here. I mean, I think that – and some of you have written about this, it won’t have the desired effect, right? It’s not going to improve things at the pump for U.S. consumers. This is a global and integrated market. And as a consequence, we think that as it’s thought through more, it becomes less and less likely to happen.

Got it. That’s very helpful. Appreciate the time.

Good afternoon, guys. Could you talk – you mentioned on CCS, and I’m just wondering maybe in broad strokes, can you talk about the type of opportunities you may be seeing near-term or the magnitude of that? Obviously, I think you guys have a lot of things going on. I’m just wondering what you can talk about? Maybe any details.

Yes, I will start and ask Anthony to – Anthony Ashley, who runs that group to weigh in. But I think, look, the – out of the IRA, the Inflation Reduction Act, there was an increase in the 45Q credit, which is a refundable credit, and that increase in the credit has made more sources of CO2 economic for capture. So picking up things like ammonia plants, so we started with kind of processing plants and ethanol plants. Now it’s picking up things like ammonia plants, cement, some coal plants, and some natural gas plants. And so we had active discussions going on that kind of paused while we were seeing how that worked out. And then those discussions started picking up. Anthony?

Yes. As Steve mentioned, definitely seen increased activity since the IRA passed. I would say our focus areas have been around our existing footprints in West Texas that seem to be off of gas processing plants, which are a little bit smaller opportunities. I would say those are probably the most likely near-term opportunities that happen in the space. But we are having much larger conversations around the U.S., especially around the bigger emissions areas, but those will take a little bit longer to develop and to be able to discuss with you guys.

Got it, guys. Great details. And then just one follow-up. I don’t know if you could say anything, just what do you say currently with – you mentioned the downtime of the volumes associated around Freeport, and I just didn’t know if there is any update you could say what’s going on there?

We don’t have anything other than what you can find out in reading in public and from the company itself.

Hi, thank you. I wanted to start on RNG. Just curious if you have any takeaways from the BP, Archaea deal and I guess how you’re thinking about the competitive landscape over the long run? And relatedly, are you open to a larger platform deal like this? Or is it pretty clear you’re going to focus more on organic development there?

BP is best to speak on the deal and the prices where they are getting synergies and other sources of value. But just on a bare kind of EBITDA multiple basis, without taking into account those other things that they bring to the table, it’s a very attractive valuation and well above that $1.2 billion that identified earlier based on our investments, our acquisitions, and the things that we’re doing. I would say that the focus here is less on M&A at this point. We have a nice platform there, but we continue to have active discussions that are more organic growth.

Hi. Good afternoon, everyone. To quickly follow on to – I think it was Keith’s question earlier on RNG. Could you maybe speculate on the value attributed to KMI versus what the Archaea valuation was and how you feel about the options or – curious how you feel about the option you mentioned earlier about maybe like a separate public vehicle down the road?

Yes. So, I mean look, as I try – I am not commenting on BP’s economics, okay. They have a lot that they bring to the table across their portfolio, their users of RINs. There are a whole bunch of things going on there. So, my comment earlier was about really just focusing on the EBITDA and what that multiple looks like in, call it, the middle decade. And if you apply that multiple to ours, it’s a couple of times at least what we have invested in this business or expect to invest when all those facilities are up and running. And so – and that’s probably appropriate, right. It’s a growing business and a growing opportunity. It’s why we are in it. And we think we will do well with it. Is there an opportunity to monetize at some point in the future when you reach critical mass? Yes. But we also like the business. And so we would have to compare those alternatives when we get there.

Got it. That’s helpful. And then on the product segment, can you give a little extra detail on the lower crude volumes maybe where it stands today, if those have fully recovered from the weather outage? And then also, if you can talk a little bit about how lower refined product prices affected margins. Trying to think of what’s structural and what’s variable to this quarter?

Yes. So, the biggest driver in crude for the quarter was on HH volumes. So, on HH, they were down roughly 26% year-over-year. And the biggest driver on that is some of the Canadian upgraders are down, which has had, I think, PADD 2 refiners paying a pretty good premium for Bakken barrels, which has decreased the basis differential to both Guernsey and Cushing, which has had an impact on that. And so hopefully, we will see that as the upgraders come back, that we will start to see a little bit of that basis come back and some additional barrels come on HH. Hiland Crude, to your point, has – or to Steve’s point, has come back from the winter storms in April. We are reasonably close to flat for the prior year, a little bit less than what we had hoped in our budget. We budgeted for 186 wells. Right now, we are forecasting about 154, but a good chunk of those are coming in, in the fourth quarter. And we are seeing some improvements on Hiland Crude in the fourth quarter, and we are looking at hopefully somewhere in the neighborhood of going from kind of, call it, flat to prior year to, call it, 7% above for Hiland Crude. So, we are hoping to see some improvements in the fourth quarter.

Okay. Great. And then any comment on the refined product pricing maybe impacting margins and how to think about that going forward? I guess it’s mostly on like the transmix business.

Are you asking about retail prices impacting demand on refined products, or you are asking about – what did you ask? We don’t understand.

Specifically about any variability in your margin that you receive from maybe transmix volumes that fluctuate with refined product commodity prices?

Yes. Well, what I would say is we had – to David’s point, we had – we took a low comp adjustment for closing price as of September, the way that works. Clearly, we can’t – with a low comp adjustment, we can’t write it back up. But as we cycle inventory at higher prices, we can move it through, and it works through margin. And right now, where prices are, they are higher than where we marked from a LOCOM perspective. So, I don’t have a specific number on that, but generally speaking, they are high, and you would expect as that inventory cycles through that, that would be a positive.

Alright. Ted, let’s go ahead and open up the channel for questions here and I’ll just remind everybody, limit yourself to one question and a follow-up. And then if you’ve got more, get back in the queue, and we will get to you and get your questions answered. And also, we have a good chunk of our management team sitting around the table here today, and I’ll make sure that you hear from them on questions about their businesses. Alright. Ted, with that, let’s take the first question.

Hi. Thanks for squeezing me back in here real quick. Just want to see, after Matterhorn, what your thoughts are on cadence Permian gas production and the need for incremental infrastructure, what type – what year do you think that might materialize at that point?

Is it again – Permian, incremental Permian takeaway?

Yes.

So, it’s very fluid. I mean I think the fundamentals would say later in the decade, but I think some of our customers based on their destination desires may say sooner than that. So, I think sometime between 2025 and 2026 at the earliest, but I think the fundamentals may say potentially even a little bit later.

So a range of like 2025 to 2028, is that what you are thinking about kind of bookending it, just to make sure I understand it correct?

Yes. You got it.

That’s for a big new long haul.

Yes. I mean I think expansions can still be supported along the way, but for a big Greenfield project, I think that’s kind of the timeline.

Got it. And just last one real quick. Elba, great price tag there. Do you see other bids like that in the marketplace right now? Just wondering how you see the market interest rates moving up, I thought might depress some interest from private equity, but obviously, you have quite a nice price tag there. So, just trying to get a feeling on the market and your desire to transact.

Yes. Look, I think we had a unique interesting opportunity around Elba that we were able to capitalize on, and we are happy with the price, not just from the price for the base assets, but also the ability to maintain the upside there. But I think interest rates historically have helped drive some of the valuations around infrastructure investors in assets. And so those are rising and probably eating a little bit into the returns that we continue to see interest across the midstream space for our assets from infrastructure investors, particularly as people think about the terminal value opportunities longer term for the space.

Okay. Well, thank you very much. And for you baseball fans, it’s only a couple of hours to the American League Championship Series. For all of you people from New York, good luck.

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