Welcome to the quarterly earnings conference call. Today’s call is being recorded. If you have any objections, you may disconnect at this time. All participants are in a listen-only mode until the question-and-answer portion of today’s call. I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Jordan. And as I always do, 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 disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations, and risk factors, which may cause actual results to differ materially from those anticipated and described in such forward-looking statements. Let me start by saying that in these turbulent and volatile times, it seems to me that every public company owes its investors a clear explanation of its strategy and its financial philosophy. In these days, platitudes and unsubstantiated hockey stick growth projections don’t play well. To my way of thinking, despite the pronouncements of celebrities, fortune may not favor the brave so much as it favors cash. The ability to produce sizable amounts of cash from operations should be viewed as a real positive in picky investments. But I believe that generating cash is only part of the story. The rest is dependent on how that cash is utilized. At Kinder Morgan, we consistently produce solid and growing cash flow, and we demonstrated that once again this quarter. At the Board and the management level, we spend a lot of time and effort deciding how to deploy that cash. As I’ve said ad nauseam, our goals are to maintain a strong investment-grade balance sheet, fund expansion and acquisition opportunities, pay a handsome and growing dividend, and further reward our shareholders by repurchasing our shares on an opportunistic basis. As Steve and the team will explain in detail, we used our funds for all of those purposes in the second quarter. To further clarify our way of thinking, we approved new capital projects only when we are assured that these projects will yield a return well in excess of our weighted cost of capital. Obviously, in the case of new pipeline projects, most of the return is normally based on long-term throughput contracts, which we are able to negotiate prior to the start of construction. But we also look at the long-term horizon, and we’re pretty conservative in assumptions on renewal contracts after expiration of the base term and on the terminal value of the investment. That said, we are finding good opportunities to grow our pipeline network as demonstrated by our recent announcement of the expansion of our Permian Highway Pipeline, which will enable additional natural gas to be transported out of the Permian Basin. So, if we’re generating lots of cash and using it in productive ways, why isn’t that reflected at a higher price per KMI stock? Or to use that old phrase, 'If you’re so smart, why aren’t you rich?' In my judgment, market pricing has disconnected from the fundamentals of the midstream energy business, resulting in a KMI dividend yield approaching 7%, which seems ludicrous for a company with the stable assets of Kinder Morgan and the robust coverage of our dividend. I don’t have an answer for this disconnect. And it’s easy to blame factors over which we have no control, like the mistaken belief that energy companies have no future or the volatility of crude prices, which, in fact, have a relatively small impact on our financial performance. Specific to KMI, some of you may prefer that we adopt a 'swing for the fences' philosophy, rather than our balanced approach, while others may think we should be even more conservative than we are. To paraphrase Abe Lincoln, I know we can’t please all of you all the time, but I can assure you that this Board and management team are firmly committed to returning value to our shareholders and that we will be as transparent as possible in explaining our story to you and all of our constituents.

We’re having a good year. We’re projecting to be nicely above plan for the year and substantially better year-over-year in Q2-to-Q2, as Kim and David will tell you. Some of the outperformance is commodity price tailwinds, but we’re also up on commercial and operational performance. And here are some highlights. Our capacity sales and renewals in our gas business are strong. Gathering and processing are also strong, up versus planned and up year-over-year. Existing capacity is growing in value. I’ll give you an example. After years of talking about the impact of contract roll-offs, we’re now seeing value growth in many places across our network. One recent example on our Mid-Continent Express Pipeline, we recently completed an open season where we awarded a substantial chunk of capacity at maximum rates. Those rates are above our original project rate. While not super material to our overall results, I think it’s a stark and good illustration of the broader trend of rate and term improvements on many of our renewals in the Natural Gas business unit. Second, at CO2, SACROC production is well above plan. And of course, we are benefiting from higher commodity prices in this segment. The product segment is ahead of plan and terminals are right on plan. We’re facing some cost headwinds, mostly because of added work this year. While costs are up, we’re actually doing very well in holding back the impacts of inflation. It’s hard to measure precisely, but based on our analysis, we are well below the headline PPI numbers that you’re seeing. And actually, we appear to be experiencing less than half of those increases. That’s due to 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. A few comments on capital allocation. The order of operations remains the same as it has been for years. First, a strong balance sheet; we expect to end this year a bit better than our 4.5x debt-to-EBITDA target, giving us capacity to take advantage of opportunities and protect us from risk. As we noted at our Investor Day this year, having that capacity is valuable to our equity owners. Second, we invest in attractive opportunities to add to the value of the firm. We have found some incremental opportunities and expect to invest about $1.5 billion this year in expansion capital. And notably, we added an expansion of our Permian Highway Pipeline. We picked up Mas Energy, a renewable natural gas company. And we’re close on a couple more nice additions to our renewable Natural Gas business. We are finding these opportunities and others all at attractive returns well above our cost of capital. Finally, we returned the excess cash to our investors in the form of a growing well-covered dividend and share repurchases. So far this year, we have purchased about 16.1 million shares while raising the dividend 3% year-over-year. As we look ahead, we have a $2.1 billion backlog, 75% of which is in low-carbon energy services. That’s natural gas, RNG as well as renewable diesel and associated feedstocks in our Products and Terminals segment. Again, all of these are attractive returns. And I want to emphasize, as we’ve said, I think many times now, our investments in the energy transition businesses we have done without sacrificing our return criteria, a nice accomplishment. In Natural Gas, in particular, we are focused on continuing to be the provider of choice for the growing LNG market where we expect to maintain and even expand on potentially our 50% share. And in natural gas storage, which is highly cost-effective energy storage in a market that will continue to need more flexibility. Again, we are having a very good year. We are further strengthening our balance sheet, finding excellent investment opportunities and returning value to shareholders, and we are setting ourselves up well for the future.

Thanks, Steve. Starting with the Natural Gas business segment for the quarter. Transport volumes were down about 2%. That’s approximately 0.6 million dekatherms per day compared to the second quarter of 2021. That was driven primarily by reduced volumes to Mexico as a result of third-party pipeline capacity added to the market, a pipeline outage on EPNG and continued decline in the Rockies production. These declines were partially offset by higher LNG deliveries and higher power demand. Deliveries to LNG facilities off of our pipelines averaged approximately 5.8 million dekatherms per day, about 16% higher than the second quarter of '21 but lower than the first quarter of this year due to the Freeport LNG outage. Our current market share of deliveries to LNG facilities remains around 50%. We currently have about 7 Bcf a day of LNG feed gas contracted on our pipes. And we’ve got another 2.6 Bcf a day of highly likely contracts where projects have been FIDed but not yet built or where we expect them to FID in the near term. We’re also working on a significant amount of other potential projects. And given the proximity of our assets to the planned LNG expansions, we expect to maintain or grow that market share as we pursue those opportunities. Deliveries to power plants in the quarter were robust, up about 7% versus the second quarter of '21. The overall demand for natural gas is very strong. And as Steve said, that drives nice demand for our transport and storage services. For the future, we continue to anticipate growth in LNG exports, power, industrial and exports to Mexico. For LNG demand, our internal and Wood Mac numbers project between 11 and 15 Bcf a day of LNG demand growth by 2028. Our natural gas gathering volumes in the quarter were up 12% compared to the second quarter of '21. Sequentially, volumes were up 6% with a big increase in the Haynesville volumes up 15% and Eagle Ford volumes up 10%. These increases were somewhat offset by lower volumes in the Bakken. Overall, our gathering volumes in the Natural Gas segment were budgeted to increase by 10% for the full year, and we’re currently on track to exceed that number.

Thanks, Kim. For the second quarter of 2022, we’re declaring a dividend of $0.2775 per share, which is $1.11 per share annualized, up 3% from our 2021 dividend. And one highlight before we begin the financial performance review. As Steve mentioned, we took advantage of a low stock price by tapping our Board-approved share repurchase program. Year-to-date, we’ve repurchased 16.1 million shares for $17.09 per share. We believe those repurchases will generate an attractive return for our shareholders. Our savings from the current dividends alone without regard to terminal value assumptions or dividend growth in the future is 6.5%, a nice return to our shareholders. Moving on to the second quarter financial performance. We generated revenues of $5.15 billion, up $2 billion from the second quarter of 2021. Our associated cost of sales also increased by $1.7 billion. Combining those two items, our gross margin was $254 million higher this quarter versus a year ago. Our net income was $635 million, up from a net loss of $757 million in the second quarter of last year, but that includes a noncash impairment item for 2021. Our adjusted earnings, which excludes certain items including that noncash impairment, was $621 million this quarter, up 20% from adjusted earnings in the second quarter of 2021. As for our DCF performance, each of our business units generated higher EBITDA than the second quarter of last year. The Natural Gas segment was up $69 million with greater contributions from Stagecoach, which we acquired in July of last year; greater volumes through our KinderHawk system; and favorable commodity price impacts on our Altamont and Copano South Texas systems. Those are partially offset by lower contributions from CIG. The Product segment was up $6 million driven by favorable price impacts, partially offset by lower crude volumes on Hiland and HH as well as higher integrity costs. Our Terminals segment was up $7 million with greater contributions from expansion projects placed in service, a gain on a sale of an idled facility, and greater coal and pet coke volumes. Those are partially offset by lower contributions from our New York Harbor terminals and our Jones Act tanker business versus the second quarter of last year. Our CO2 segment was up $60 million, driven by favorable commodity prices, more than offsetting lower year-over-year oil and CO2 volumes as well as some higher operating costs. Also adding to that segment were contributions from our Energy Transition Ventures renewable natural gas business, Kinetrex, which we acquired in August of last year. The DCF in total was $1.176 billion, 15% over the second quarter of 2021. And our DCF per share was $0.52, up 16% from last year. It’s a very nice performance. On to our balance sheet. We ended the second quarter with $31 billion of net debt and a net debt to adjusted EBITDA ratio of 4.3x. That’s up from year-end at 3.9 times, although that 3.9 times includes the nonrecurring EBITDA contributions from the Winter Storm Uri event in February 2021. The ratio at year-end would have been 4.6 times excluding the Uri EBITDA contributions. So, we ended the quarter favorable to our year-end recurring metric. Our net debt has decreased $185 million year-to-date, and I will reconcile that change to the end of the second quarter. We’ve generated year-to-date DCF of $2.631 billion. We’ve paid out dividends of $1.2 billion. We’ve spent $500 million on growth capital and contributions to our joint ventures. We’ve posted about $300 million of margin related to hedging activity. Through the second quarter, we had $170 million of stock repurchases. And we’ve had approximately $300 million of working capital uses year-to-date, and that explains the majority of the year-to-date net debt change. And with that, I’ll turn it back to Steve.

Thank you. We will now begin the Q&A session. Please remember to limit your questions to one question and one follow-up. If you have additional questions, please return to the queue, and we will address them. We have a significant portion of our management team available to respond to your inquiries regarding their businesses. Jordan, you can start the Q&A.

Thank you. Our first question comes from Jeremy Tonet from JP Morgan.

I don't think Bitcoin should be prioritized for organic growth projects in the near future. Moving on to the Permian, could you share the latest perspective on when takeaway tightness might occur? Additionally, I'm curious about what is needed to reach FID for GCX if the basin is tight, and whether this could happen soon.

Tom?

Yes, I believe that with the projects that have reached Final Investment Decision and are moving into the construction phase, there may be some short-term tightness. However, once these projects are operational, we expect the market to be adequately supplied until later in the decade. Therefore, the next projects will probably need to reach Final Investment Decision around 2024 or possibly 2025. Additionally, there may still be near-term opportunities for GCX as we are in discussions with several potential customers for specific capacity needs, especially to cater to LNG markets. Overall, at least in the short to intermediate term, the markets seem to be well supplied.

And GCX is fast to market, has a compression expansion. The FID is in the middle part of the decade or 27 to 30 months to complete roughly.

Got it. So I just want to confirm there, back half of the decade next pipe, you said there as far as beyond what’s currently out there?

That sounds right.

Got it. And real quick, just on the renewable natural gas. Just wanted to see if you could provide more details on the acquisition here Mas CanAm. As far as the economics, what type of renewable credits were kind of baked in their expectations? And should we expect kind of more acquisitions of this nature going forward? Is this an area that’s ripe for consolidation for Kinder to go after? Just wondering broader thoughts there.

Anthony?

We are excited about the acquisition, which includes three landfill gas assets and one RNG facility in Arlington, representing the majority of the value at $355 million. We also acquired two medium-BTU facilities in Shreveport and Victoria. This deal differs from the Kinetrex acquisition, as it features an operating asset that is mostly derisked. Arlington has advantageous royalty arrangements and long-term contracts in the transportation market, minimizing risk. The long-term EBITDA multiple stands at around 8 times.

Okay. And the prospects for additional?

Yes. And so I think, as Steve mentioned, we have line of sight for some additional growth. There are some opportunities on the M&A side, but I think largely, we’ll be looking to grow organically in the future.

Got it. That’s helpful. Thank you.

You’re right, Jeremy. Bitcoin is not even in the shadow backlog.

Didn’t think so. Thank you.

Our next question comes from Jean Ann Salisbury with Bernstein.

Hi. Have your operations had to adjust for the Freeport outage? Can you talk about if you’re seeing more flows into Louisiana or Mexico are getting absorbed by Texas weather, or are you just kind of not getting paid from some of it if they did force majeure?

Yes. So, I would say fairly immaterial financial impact to us. But as far as an impact to the market, we’re certainly seeing the basis market in the Katy Ship Channel area weaken with the additional volumes that are hitting the Texas market. I think it helps support storage, Gulf Coast storage more broadly. But certainly, it has been at least partially offset by the extreme power demand that we’ve been seeing here in Texas and along the Gulf Coast. And I would say just with the connectivity with the interstate pipeline grid between intras and interstates that those volumes are getting pretty well dispersed.

Great. And then, my second question is very long term. I’m getting asked about this from generalists, and I want to make sure I’m getting it right. Just kind of want to understand refined product pipes is the common concern that I’m hearing. If we play out an energy transition scenario, we’re flowing them and 15 years is much lower than today, let’s say. Can you talk about what would happen to the pipe revenue for refined product pipes? Is it mostly cost of service-based or negotiated or some of those?

Yes, Dax?

Yes. I would first say that it depends on where the situation occurs. From an economic protection standpoint, we have the capability to adjust. We’ve been implementing measures on the pipelines to account for reduced volumes, allowing us to increase rates for our protection. California has been particularly forward-thinking in discussions about possibly banning internal combustion engines. However, this primarily relates to road fuels consumed in California, from which we transport a substantial amount of products to other states. Our analysis showed that this situation could impact about 11% of products' EBITDA based on 2019 data. Therefore, California represents the most progressive example in this context, and that’s the perspective we have from our segment before considering tariff protections.

Yes. There is a noticeable difference between how products pipelines operate compared to natural gas pipelines. We frequently engage in negotiated rate transactions within the natural gas pipeline grid. In contrast, the regulated interstate and intrastate refined products pipelines are usually governed by cost of service regulation as common carriers. We recently resolved a long-standing rate case concerning our SFPP system and have another ongoing case for our interstate operations with the CPUC. Economically, these pipelines are the most efficient way to transport products from one location to another, which gives them a strong market position. If there were a drop in volume, one could argue for a rate increase as the same service costs would be distributed over fewer barrels. However, this isn't how we operate, except for the California intrastate market. Thus, there is a different dynamic between the refined products pipelines and the natural gas pipelines.

We can transport renewable diesel through our pipelines. If there's a shift, renewable diesel can be accommodated. Additionally, sustainable aviation fuel can also be moved through our pipelines. These are products that can serve as replacements.

Our next question comes from Colton Bean with Tudor, Pickering, Holt & Co.

On the guidance increase, it looks like an EBITDA step-up of $350 million or better. I guess, first, are there any offsets at the cash flow level that results in DCF also being 5%, or is that just a function of rounding? And then second, I think you all flagged about $750 million of discretionary cash on the original budget. Should we assume the guidance increase is additive to that total, including the $100 million bump in CapEx last quarter?

The items that are negatively impacting the difference between EBITDA and DCF for us are interest expense and sustaining capital. Interest expense is higher than our budget because short-term rates are significantly above what we had planned, and longer-term rates have also increased slightly. Additionally, our sustaining capital includes some unexpected class change costs and a rise in inflation affecting our costs. Regarding the available capacity we mentioned earlier this year, the $750 million was based on our budgeted EBITDA and projected spending for the year. Our EBITDA has improved, which has increased our balance sheet capacity. However, our spending has also gone up more than we had anticipated due to the Mas transaction and some extra projects in our discretionary spending. We've also repurchased shares that were not accounted for in our budget. Overall, our available capacity is still greater than our budgeted amount, but we have also spent significantly more than originally planned.

Great. And then, David, maybe just sticking on the financing side of things. I think you all noted that you had locked in roughly $5 billion of your floating rate exposure through the end of this year. Any updates or shifts in how you’re thinking about managing that heading into 2023?

Yes. We haven’t had a similar chance to secure favorable rates for 2023, so we’re very pleased we locked it in for this year. It has provided us with almost a $70 million benefit this year. We will continue to explore ways to potentially mitigate that going into 2023, but so far, we haven’t identified any favorable opportunities to do that. Currently, we are experiencing increasing pressure on short-term rates as we progress through the year. With the recessionary pressures in the market, it seems things are starting to ease up a bit. We will keep an eye on it, but there haven’t been any developments yet.

Our next question comes from Chase Mulvehill with Bank of America.

I guess, I wanted to come back and kind of hit on guidance a little bit. I guess, just specifically on gathering volumes, I think you guided up originally 10%. And I think you noted you’re going to be above that, and you kind of mentioned that in last quarter’s conference call as well. And you’ve obviously given us the sensitivity here that we can use towards your guidance. So, how much do you think that gathering volumes will be up now? And I guess, maybe what’s included in the updated guidance?

We believe it will increase by approximately 13% compared to the original guidance of 10%, and this is reflected in our updated guidance.

Okay, great. Can I ask a more technical question regarding brownfield Permian egress expansions? How should we understand the timing and how this additional capacity will facilitate incremental volumes? Essentially, will you be able to gradually increase volumes as you add each new compression station, or will all the additional production begin simultaneously once all the compression stations are in place?

No. I think it’s more of a light-switch experience as we approach November, December ‘23. There’ll be certainly test volumes, additional volumes that we do test along the way. But I think to get to the ultimate delivery point where the customers want to go, that will all happen November, December ‘23.

Our next question comes from Michael Blum with Wells Fargo.

I wanted to maybe just start with the opening comments about the stock price. I’m just wondering if you could expand a little more there. And I guess, specifically, are there any specific actions that you’re contemplating that impact the stock price here?

I've realized for a long time that the management team's ability to affect the stock price is quite limited. However, I want to emphasize that it's not only about Kinder Morgan. There is a significant disconnect in how the market values midstream energy companies. For example, there is a stronger correlation between our stock and crude oil prices than there should be. We inform everyone at the beginning of the year about the expected impact of changes in crude and natural gas prices. As the year progresses, that impact becomes relatively minor. This is just one instance of what I believe is a market overreaction. The best approach for us as a management team and Board is to consistently highlight the strength of our cash flow and how wisely we are utilizing it. We have shown this in our cash deployment during this quarter. So, our strategy is straightforward and perhaps not very creative. However, in the long run—much like the tortoise and the hare—we believe we will be rewarded for the consistent performance we've delivered quarter after quarter.

Thank you for those comments. My second question is directed at you, Anthony. Congratulations on your expanded responsibilities. With your promotion to oversee both energy transition and CO2, can I infer that this indicates improved prospects for carbon capture by aligning these two areas?

Look, I think we feel like there are some synergies there, and I’ll ask Anthony to expand on that. But I mean we’ll use the same geologist for carbon capture and sequestration as we do for CO2. I mean, we’ve been sequestering CO2 for decades, and we use it in connection with enhanced oil recovery operations obviously. But it’s the same technology, if you will. And so, we think there is synergy there, and there are a few others. But I’ll turn it over to Anthony to answer the rest.

Yes. I mean, obviously, Jesse had a great opportunity, and we wish him well. And it’s a great opportunity for me. And I’ve inherited a really great team. So I appreciate that. I don’t think you’re going to see anything materially different from the way we kind of run things moving forward. As Steve mentioned, I think as we have been moving forward with ETV, it’s become more and more apparent there’s a lot of overlap, especially with the CO2 group. So a lot of technical experience there that we’ve been using. And we’ll be further integrating those groups and taking advantage of that. And I think that will provide some nice commercial synergies down the road. But, we don’t have anything special to announce. And I don’t think you’re going to see the way we run the CO2 business or ETV to be materially different from the way Jesse was doing.

Yes. I believe the integration benefits will be significant as we share the same operations organization. For acquisitions we made, having a unified operations platform will be beneficial. Additionally, we have a common project management platform, which adds to our efficiency. Our centralized procurement organization has always been a strength, and leveraging its capabilities for development opportunities will yield positive results. However, this is not focused on carbon capture, utilization, and storage. We see potential in that area, but it's developing slowly, and there are still unresolved issues regarding 45Q tax credit levels. Overall, the business fits well together and will remain cohesive.

Our next question comes from Keith Stanley with Wolfe Research.

First, wanted to ask just on the next wave of LNG projects. So, you have this $600 million project you’re announcing on TGP and SNG tied to Plaquemines. Can you talk to which specific LNG projects we should track more closely that you see more opportunity to potentially provide gas services to? And is there any way to frame the potential investment opportunity in dollars around new LNG projects in the next five years? So, should we expect other $600 million-type investment opportunities tied to the next wave of projects?

Yes, I don’t want to label anyone as winners or losers, but I believe those who have found success so far have a strong chance of continuing to succeed over time due to their expanding operations. We’re also very optimistic about some new partners we are collaborating with to grow alongside the Texas and Louisiana Gulf Coast. Given the closeness of our operations, we are engaging with all these developers to explore ways to broaden our presence and even develop some new projects to support their growth. We are very positive about this opportunity and believe there is a significant investment potential in the next three to five years.

Yes. As a result, some of the opportunities will allow us to utilize capacity on our existing system or add compression, making them very efficient. Other opportunities will require some level of new development. Therefore, it will involve a combination of both.

And I think the macro opportunity here is incredible. I’ll come back to what Kim said, depending on which expert you listen to, the projections are that over the next five years or so, you’re going to have 11 to 13 or 14 Bcf a day in growth in LNG. We fully expect to be able to maintain our 50% share, which we have now. That’s an incredible increase in throughput, a lot of which is attributable to the present system that we have in place along the Texas and Louisiana Gulf Coast. It’s an incredible green shoot for Kinder Morgan.

And a separate question, I guess, kind of revisiting Michael’s question from earlier. So, the Company hasn’t really done material stock buybacks since really 2018. And it looks like you did 270 million. The average price implies that was kind of done over the past month for the most part. So I know you’ve talked about being bullish on the stock price, but just any other color on what changed in the market or just the decision process? Because it’s a pretty material step-up in buybacks in a brief period. And how you’re thinking about that, I guess, over the balance of the year since you still have available capacity?

I’ll begin, and then David can add to it. We planned to assess how the year was shaping up in the first quarter to build confidence in our outlook. Given the uncertainty in the market, we experienced strong cash flows bolstered by secured contracts, which lends stability to our business. We aimed to evaluate how the year was progressing. Overall, things appeared promising; we indicated a positive outlook for Q1. I believed we would exceed our guidance, though I didn’t provide specific figures. This situation presented a good opportunity for us to utilize some of our capacity while adhering to our strategic approach to share repurchases, and we intend to maintain this strategy moving forward. While we can't definitively predict, we anticipate having further opportunities throughout the year.

One thing I think Steve covered is that we plan to balance the additional spending we've already incurred with the extra capacity generated from our EBITDA outperformance. We will consider both factors along with our opportunistic share repurchases for the remainder of the year.

Our next question comes from Marc Solecitto with Barclays.

With inflation tracking where it is, that should be a nice tailwind for your products business. Just wondering if you can maybe comment on how that interplays with the broader macro and any competitive dynamics across your footprint and your ability to fully pass that through.

Dax, why don’t you start?

Yes. Based on the Producer Price Index, we adhere to the Federal Energy Regulatory Commission's methodology for our policy related to two pipelines, which is currently set at PPI FG minus 0.21%. We implemented an 8.7% rate increase on July 1st across our assets. If the PPI continues on its current trajectory and we proceed with the expected full implementation, we anticipate an increase of around 15% next year.

Thank you for the information. Regarding your capital expenditures, should we expect the majority of the $1.5 billion budget for this year to be allocated to PHP in 2023? Can you provide any details about the cost components associated with these expansions? Additionally, for Evangeline Pass, might we see an increase in capital expenditures this year depending on commercial agreements, or will that predominantly occur in later years?

They’re going to be delayed, yes, partly because we have a regulatory process to go through. However, for PHP, most of the spending will occur in 2023.

And the ‘23 will be incorporated in the $1.5 billion.

Our next question comes from Michael Lapides with Goldman Sachs.

Hey, guys. Congrats on a good quarter, and congrats to Tom and to Anthony for the movement around the greater opportunities. One kind of near-term question. Refined products pipeline volume or throughput during the quarter, a little bit weak on gasoline, a little bit weak on diesel. Can you just kind of talk about whether that’s geographic specific to you, whether that’s more just general demand destruction due to price, especially on the diesel side?

Dax.

Yes. We are seeing a little bit of demand destruction a bit across the system, I would say, on road fuels. Jet fuel, as you would expect, as you see naturally a pretty strong increase. I mean, I think the EI numbers on jet are about 18. As Kim said, we’re about 19 on diesel. You saw a larger decrease on our assets. EIA was just right around 3%. We were closer to 11%. But I will remind you on diesel, we are still within 2% of where we were in 2019. We saw a big jump last year on diesel volume. So, while we’ve seen come off compared to Q2 of last year, it’s still pretty robust. But we have seen a little bit of demand destruction. But I think you’ve seen gasoline prices across the country come off for, I want to say, 35 days straight. So, we’ve seen customer response. We’ve also seen price response.

Got it. I have a follow-up for Anthony regarding the landfill gas deal you announced today. You mentioned a build multiple of roughly 8 times. Is that for the first year, and as we consider the long term, will this multiple improve as production increases, or do you expect that to be a steady state? Also, how does this compare to the EBITDA and returns on capital from your core natural gas pipeline business?

Yes, it increases to 8 and improves from there. There is growth at this landfill, primarily driven by the Arlington asset. We have perpetual gas rights there, and there is potential for expansion in the future. The EBITDA multiple improves over time. I would say the 8 times represents an average over the medium term. In terms of natural gas, we consider various types of opportunities, and it’s very different from other investments. It’s not necessarily a straightforward comparison. However, regarding our RNG portfolio, these assets are largely de-risked and currently operational. We have long-term gas rights with Arlington as a growth opportunity, making it an attractive acquisition in this sector.

And as a general comment, Michael, but as we said at the beginning, we have not had to sacrifice our return criteria and have not had to sacrifice the margin above our weighted average cost of capital to be able to invest in these things. We’ve been very selective about how we’ve entered this sector.

Our next question comes from Brian Reynolds with UBS.

I’m curious just on Ruby Pipeline, if there’s any updates on the bankruptcy proceedings and if there are any initial thoughts on a near-term resolution as it relates to nat gas service and if there’s any commentary on potential long-term CO2 transport, given a regional peer looking to do the same.

Yes. In terms of the bankruptcy proceeding, Ruby has in place an independent set of managers who have been managing a lot of the day-to-day on the proceedings. There has been some recent court activity around a timeline proceeding forward around a potential 363 sale and just getting to a resolution of the case along a certain timeline. So, that’s where it stands. I can’t comment on any specific negotiations or discussions with parties involved. I will point to our prior comments on this, which is anything that KMI does around Ruby is going to be in the interest of KMI shareholders. I think as it relates to your question around potential conversion of CO2 service on the pipe, I think first, the pipe does continue to serve a need for the California market. And so, it is a pipe that has good service and natural gas service today. But across our network, we are looking at repurposing opportunities. But I think our general view at this point is those are longer-dated opportunities.

Great. I appreciate the color. And then a quick follow-up on the guidance raise just given some of the acquisitions during the year. Curious if you could just kind of break out organic raise versus the contribution from some of the acquisitions year-to-date. Thanks.

Yes, we see some benefits from commodity prices, but our underlying base business is also contributing positively. We're experiencing attractive renewals in the Natural Gas sector across several areas, including our Texas Intrastate operations, NGPL, and growth in our gathering business. Much of this reflects the organic strength in those contracts as they expire. Additionally, there is some impact from expansion capital, but much of our budgeting is based on what we expect at the beginning of the year. Initiatives we approve within the year typically benefit future years as well. Therefore, you can attribute this to a combination of favorable commodity prices and organic growth within our existing operations.

Because things like Stagecoach, we budgeted expansions that we knew about before the year started; we budgeted. And most expansions that we found that we’re doing this year don’t come on until 2023 or 2024 and beyond.

Our next question comes from Michael Cusimano from Pickering Energy Partners.

Two questions for me. First, just is it fair to assume that the declines on Hiland and HH were weather-related? And can you talk through like how that’s recovered and maybe how the volume growth outlook has changed, if any, going forward?

Do you have an answer on the volumes, Dax?

Yes, definitely. On Hiland, I would say the overwhelming majority of it is. I mean, just to give you some of the numbers, and that was the unexpected storm that came through in April. We were doing roughly north of 200,000 barrels a day prior to that. In April, we ended up doing 163,000 and then we averaged about 188,000 for the quarter, but we’re back in June doing roughly 207,000. So it was a big chunk of it. For HH, less. That has a lot more to do with the spreads out of the Bakken, but it was absolutely the issue for the period.

And the gas lines have recovered back to sort of pre-outage levels.

Our next question relates to the Terminals business. You mentioned that utilization and rates have decreased slightly due to backwardation, and it seems that the Jones Act has hit a low point. Am I mistaken in thinking that we may have established a new base level for that segment, or are there other factors I should consider?

No, you’re correct. I mean, the rate degradation that we’ve seen is specifically just in the New York Harbor. We’ve seen rates actually return to the levels we saw last year in the Houston area, and we’re back to 100% utilization there. As it relates to APT, we saw a trough last year, rates descending into the mid-50s per day. And they are back into the mid-60s now. We’re 100% utilized. All of the vessels are moving, and we’re actually seeing an increase in term. Where we were around two-year term last year, we’re now looking at 6.2 years with likely renewals. So, the answer to your question, yes.

Gain on sale was that excluded from EBITDA?

No, it’s included in EBITDA. We have a threshold set at $15 million, meaning that anything below this amount, like a gain on sale, remains in the DCF. Any amount above that would be excluded from DCF, as it tends to be nonrecurring. We used to have a lower threshold, which added a lot of complexity to our financials and caused confusion. By raising the threshold, we’ve simplified things for our investors and better excluded truly one-time items. Occasionally, we do have land sales, so the higher threshold is a more sensible approach.

So, smaller nonrecurring pluses and minuses now get reflected.

Our final question comes from Harry Mateer with Barclays.

Just two for me. I think the first, now we’re at the midway point of the year, would like to get an update on how you’re navigating your refinancing plans. You’ve got some maturities coming due early next year. I think you could probably call them out late this year. So, how are you thinking about navigating that? And then, secondly, there was a line in the press release about expecting to meet or improve on the debt metric goal. And I just want to confirm that that’s referring to the 4.3 times budget rather than like a formal change to the approximately 4.5 times goal you guys have had for a couple of years. Thanks.

Yes, that is referring to our expectation of finishing the year better than our budgeted level. Regarding our approach to issuances and managing upcoming maturities, we have completed our maturities for 2022. Currently, we have just over $900 million in commercial paper. This is why we maintain a $4 billion credit facility to cover short-term needs when necessary. With over $3 billion in capacity available, we are not in a rush to convert that. We can afford to be patient. We may look to convert it in the near future, but we will wait for favorable conditions. Next year, we face a $3.2 billion maturity, which is significant, but we have the full year to address it. Our revolving capacity allows us to manage the timing while waiting for the right market conditions.

Okay, got it. But the Company’s formal leverage target is still 4.5 times. Is that right, David?

Approximately 4.5 times. That’s correct.

We have no more callers in the queue.

Okay. Well, thank you very much, Jordan, and thanks to everybody for listening in. Have a good day.

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