Kinder Morgan's quarterly earnings conference call. Today's call is being recorded. If you have any objections, you may disconnect at this time. All lines will be in a listen-only mode until the question- and- answer session of today's call. At that time, if you would like to ask a question, please press star followed by one, and please make sure your phone is unmuted and record your name and company clearly when prompted. I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you, sir. You may begin. Thank you, Missy. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities Exchange Act of 1934, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release, as well as review our latest filings with the SEC for important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. With that out of the way, let me just say that like a broken record, each quarter I open our call with comments on the strong cash flow we're generating and how we're using and intend to use that cash flow. Whether you look at our cash flow for the second quarter, for year to date, or our projections for the full year, it's apparent that we continue to be a strong generator of cash flow. It's also apparent that we continue to live comfortably within that cash flow. The question investors should ask on a continuous basis is whether we are wise stewards of that cash. We have said repeatedly that we would use our funds to maintain a strong balance sheet, pay a good and growing dividend, invest in new projects or acquisitions when they met our relatively high return hurdle rates, and opportunistically repurchase our shares. This quarter, we announced two fairly significant acquisitions. The first was our purchase of the Stagecoach natural gas storage and pipeline assets in the Northeast for approximately $1.2 billion. These assets expand our services to our customers by helping connect natural gas supply with Northeast demand areas. The acquisition is immediately accretive to our shareholders, and I believe it will be an important and profitable asset for KMI for many years to come. Our second acquisition was to make an attractive platform investment in the rapidly growing renewable natural gas market by purchasing Kinetrex for approximately $300 million. Steve will talk about this acquisition in detail. We believe there is a bright future for this business and other related Energy Transition businesses that we are exploring. Now, let me conclude with two important points. Both of these acquisitions meet our hurdle rates that I referred to earlier, and both are being paid for with our internally generated cash. I believe both fit within the long-term financial strategy that I speak to each quarter, and I can assure you that our board looks at all alternatives in a manner completely consistent with that financial strategy. With that, I'll turn it over to Steve. Okay, thanks, Rich. I'm going to make a couple of additional comments about the two acquisitions and then turn it over to Kim and David. On the Stagecoach storage and transportation assets for $1.2 billion, we closed that transaction earlier this month. It adds 41 BCF of certificated and pretty flexible working gas storage capacity and 185 mi of pipeline. We're excited about this transaction for several reasons. As we discussed on the first quarter call, we think storage value is going to increase over time. Its value was certainly revealed during Winter Storm Uri, and we've seen that start to show up in our commercial transactions. Storage will also become more valuable as more intermittent renewable resources are added to the grid. The Stagecoach assets are well interconnected with our Tennessee Gas Pipeline system, as well as other third-party systems in a part of the country that is constrained from an infrastructure standpoint, and frankly, where it is difficult to get new infrastructure permitted and built. We're excited about this transaction and believe it will pay off nicely for our shareholders. The second transaction, which we announced at the end of last week, was accomplished by our newly formed Energy Transition Ventures group. We put that together in the first quarter of this year. We're acquiring Kinetrex, a renewable natural gas business, subject to regulatory approval and a couple of other closing conditions. At signing, Kinetrex had secured three new signed development projects that we will build out over the next 18 months, resulting in a purchase price plus capital at a less than 6x EBITDA multiple by the time we get to 2023. With Kinetrex, we're picking up a rare platform investment in a highly fragmented market. It gives us a nice head start on working on hundreds, if not thousands, of potential renewable natural gas project candidates in the U.S. A few more points on this deal. As several of you pointed out in your comments post-announcement, the value is dependent on RINs value. You don't make money on the gas sale, with an important exception that I'll get to in a minute. Importantly, the particular RINs that this business generates are D3 RINs, which can be used to satisfy other RINs obligations as well. D3s are for advanced biofuels. Promoting more of those in the transportation fuel market has had bipartisan support and even more support from the environmental community than conventional ethanol. While there is some regulatory flexibility in EPA's hands, there is an underlying statutory framework, again with bipartisan support, combined with widely acknowledged greenhouse gas benefits. That further protects the value of this category of RINs in particular. Having said that, we believe we'll have the opportunity to mitigate our exposure to RINs pricing volatility. Based on conversations with potential customers, not signed deals yet, but conversations so far, there is significant interest in renewable natural gas in the so-called voluntary market. These are customers who are outside of the transport fuel market who are interested in reducing their carbon footprint, and we believe would transact on a long-term fixed price basis. There are also potential customers interested in sharing the risk and reward of the RINs value. We will look for appropriate ways to lock in the value of the environmental attributes on attractive terms. When we talked about our Energy Transition Ventures group in the past, we've talked about transacting on attractive returns for our shareholders, not loss leaders and not doing things for show. This deal is a great example of that. In the team's short existence so far, they've acted on an attractive opportunity, and they continue to work on a number of other specific project opportunities. Very good progress in a short period of time. These two deals illustrate a couple of key points, broader points about our business. The larger deal, Stagecoach, is a further investment in our existing natural gas business, where we own the largest transportation and storage network in the country. That reflects our view that our existing business will be needed for decades to come. Hydrocarbons, and especially natural gas, have very stubborn advantages and will play an essential role in meeting the growing need for energy around the world. That's something we are well positioned for with our assets, and especially considering our considerable connectivity with export markets, especially in natural gas, but also in refined products. At the same time, we do see opportunities in the energy evolution. I'm putting emphasis on evolution, and we're positioning ourselves there as well. We're doing this in our base business, where our gas delivery capability provides the needed backup for renewables at far lower cost and longer duration than batteries. We're doing it in responsibly sourced, that is low methane emissions, natural gas. We had our second such transaction this quarter. We're doing it in our refined products businesses where we handle renewable transportation fuels, and we are actively developing additional business in that part of our business as well. The Kinetrex transaction, while relatively small, positions us to develop a new business line in the renewable energy space at attractive returns and with a bit of a head start. The takeaway from all of this is that we continue to see strong long-term value in the assets and service offerings we have today, while also pivoting in an appropriate and value-creating way to the faster-growing parts of the energy business. With that, I'll turn it over to Kim. Okay, thanks, Steve. First, I'm going to start with our business fundamentals. Then I'll talk very high level about our forecast for the full year. Starting with the natural gas business fundamentals for the quarter, transport volumes were up 4%, or approximately [1.5 million Dth] per day, versus the second quarter of 2020. That was driven primarily by LNG Mexico exports and power demand on TGP, the PHP in service, higher industrial and LNG demand on our Texas intrastate system, and higher deliveries to our Elba Express LNG facility. These increases were partially offset by lower volumes on CIG. That's due to declines in Rockies production and Fayetteville Express contract expirations. Physical deliveries to LNG off of our pipelines averaged approximately 5 million Dth per day. That's a huge increase versus the second quarter of 2020. LNG volumes also increased versus the first quarter of this year by approximately 8%. Our market share of LNG export volumes was about 48%. Exports to Mexico were up about 20% versus the second quarter of 2020. Our share of Mexico volumes is about 54%. Overall, deliveries to power plants were relatively flat. Deliveries to LDCs were down slightly, while deliveries to industrial facilities were up 4%. Our natural gas gathering volumes were down about 12% in the quarter compared to the second quarter of 2020. For gathering volumes, though, I think the more informative comparison is the sequential quarter. Compared to the first quarter of this year, volumes were up about 6%. Here we saw nice increases in Hiland volumes, which were up about 10%, and the Haynesville volumes, which were up about 13%. In our Products Pipeline segment, refined products were up 37% for the quarter versus the second quarter of 2020. Volumes are also up about 17% versus the first quarter of this year. We saw substantial improvement both year-over-year and quarter-over-quarter. Compared to the pre-pandemic levels, and we're using the second quarter of 2019 as the reference point, road fuels, and that's gasoline and diesel combined, are essentially flat, and jet fuel is still down about 26%. Crude and condensate volumes were up 6% in the quarter versus the second quarter of 2020, and sequentially, they were up very slightly. In our Terminals business segment, our liquids utilization remains high. If you exclude the tanks out of service for required inspections, approximately 98% of our tanks are leased. Most of the revenue that we receive comes from fixed monthly charges we receive for tanks under lease. We do receive a marginal amount of revenue from throughput. We saw throughput increase significantly, about 22% in total on our liquids terminals, 26% if you're just looking at refined products. That still remains a little bit below 2019, about 6% on total liquids volumes, 5% when you're just looking at gasoline and diesel. We continue to experience some weakness in our marine tanker business. As we said last quarter, we expect that this market will improve, but it may take until late this year as the charter activity tends to lag the underlying supply and demand fundamentals. On the bulk side, volumes increased by 23%, and that was driven by coal and steel. Mill utilization of our largest steel customer exceeded pre-pandemic levels. Coal export economics improved for both met and thermal coal. In the CO2 segment, crude volumes were down about 9%, CO2 volumes were down about 10% year-over-year. Increased oil and NGL prices did offset some of the volume degradation. If you compare to our budget, we're currently anticipating that oil volumes will exceed our budget by approximately 5%, and that's driven primarily by some nice performance on SACROC. CO2 volumes we also expect to exceed our budget. Overall, we're seeing increased natural gas volumes and demand from LNG and Mexico exports, as well as industrial demand on the Gulf Coast. We're seeing increased gathering volumes in the Bakken and the Haynesville, and nice recovery of refined products volume. Crude oil volumes are above our expectations in our CO2 segment, and we're getting some price help. We're still experiencing some weakness in our Jones Act tankers, and the Eagle Ford remains highly competitive. Let me give you a very high-level update of our full-year forecast. As we said in the release, we're currently projecting full-year DCF of $5.4 billion. That's above the high end of the range that we gave you last quarter. The range we gave you last quarter was $5.1 billion-$5.3 billion. The outperformance versus the high end of the range is driven by our Stagecoach acquisition, higher commodity prices, and better refined products volumes. With that, I'll turn it over to David. All right. Thanks, Kim. For the second quarter of 2021, we're declaring a dividend of $0.27 per share, which is $1.08 annualized, and that's up 3% from the second quarter of 2020. This quarter, we generated revenue of $3.15 billion, which is up $590 million from the second quarter of 2020. We also had higher cost of sales with an increase there of $495 million. Netting those two together, gross margin was up $95 million. This quarter, we also took an impairment of our South Texas gathering and processing assets of $1.6 billion. With that impact, we generated a net loss of $757 million for the quarter. Looking at adjusted earnings, which is before certain items, primarily the South Texas asset impairment this quarter and the midstream goodwill impairment a year ago, we generated income of $516 million this quarter, up $135 million from the second quarter of 2020. Moving on to the segment EBITDA and distributable cash flow performance. Our Natural Gas segment was up $48 million for the quarter, and that was up primarily due to favorable margins in our Texas intrastate business, greater contributions from our PHP asset, which is now in service, and increased volumes on our Bakken gas gathering systems. Partially offsetting those items were lower volumes on our South Texas and KinderHawk gathering and processing assets and lower contributions from FEP due to contract roll-offs. Our Products segment was up $66 million, driven by a nice recovery in refined product volume. Terminals was up $17 million, also driven by the nice refined product volume recovery, partially offset by lower utilization of our Jones Act tankers. Our CO2 segment was down $5 million due to lower crude oil and CO2 volumes and some increased well work costs. Those are partially offset by higher realized crude oil and NGL pricing. Our G&A and corporate charges were lower by $7 million. This is where we benefited from our organizational efficiency savings as well as some lower non-cash pension expenses, partially offset by some lower capitalized G&A costs. Our JV DD&A category was lower by $27 million, primarily due to Ruby. That brings us to our adjusted EBITDA of $1.670 billion, which is 7% higher than the second quarter of 2020. Moving below EBITDA, interest expense was $16 million favorable, driven by our lower LIBOR rates benefiting our interest rate swaps, as well as a lower debt balance and lower rates on our long-term debt. Those are partially offset by lower capitalized interest expenses versus last year. Our cash taxes for the quarter were unfavorable, $40 million, mostly due to Citrus, our Products Southeast Pipeline, and Texas margin tax deferrals, which were taken in 2020 as a result of the pandemic. Just timing. For the full year, our cash taxes are in line with our budget. Our sustaining capital was unfavorable, $51 million for the quarter, driven by higher spend in our Natural Gas, CO2, and Terminals segments. That higher spend is in line with what we had budgeted for the quarter. Our total DCF of $1.025 billion is up 2%, and our DCF per share of $0.45 per share is up $0.01 from last year. On our balance sheet, we ended the quarter at 3.8x debt to EBITDA, which is down nicely from our 4.6x at year end. Kim already mentioned that we updated our full-year guidance, which now has DCF and EBITDA above the top end of the range that we provided in the first quarter. For debt to EBITDA, we expect to end the year at 4.0x. That includes the acquisitions of Stagecoach, which we closed on July 9th, and Kinetrex, which we expect to close in the third quarter. As a reminder, that our year-end debt- to- EBITDA level has the benefit of the largely non-recurring EBITDA generated during Winter Storm Uri earlier in the year, and our longer-term leverage target of around 4.5x has not changed. On to reconciliation of our net debt. The net debt for the quarter ended at almost $30.2 billion, down $1.847 billion from year-end, and about $500 million down from Q1. Our net debt has now declined by over $12 billion, or about 30% since our peak levels. To reconcile the change in the quarter in net debt, we generated $1.025 billion of DCF. We paid out approximately $600 million of dividends. We spent approximately $100 million of growth capital and contributions to our joint ventures. We had a $175 million of working capital source of cash flows, primarily interest expense accrual. That explains the majority of the change for the quarter. For the change year to date, we generated $3.354 billion of distributable cash flow. We've spent $1.2 billion on dividends. We've spent $300 million on growth CapEx and JV contributions. We received $413 million on our partial interest sale of NGPL, and we have experienced a working capital use of approximately $425 million. That explains the majority of the change for the year. That completes the financial review, and I will turn it back to Steve. All right, Missy, let's open it up for questions. Just a reminder to everyone, as a courtesy to others on the call, we ask that you limit your questions to one and a follow-up. Then if you've got more, get back in the queue, and we will get to you. All right, Missy, let's open it up. Yes, sir. If you would like to ask a question please press star followed by one. Please make sure that your phone is unmuted and record your name and company when prompted. If you wish to withdraw your question you can press star two. Our first question comes from Jeremy Tonet from JP Morgan. Your line is open, sir. Good afternoon. Good afternoon. I'm going to resist the temptation to ask about CCUS and ask about two different questions. I was just curious, I guess, with the RNG space. It seems like that's a very fragmented industry where Kinder historically has played a role in fragmented industries in being a consolidator. Do you see a similar opportunity set here? I guess also, it seems like there is a good amount of competition from private equity and those with very low cost of capital to go after these type of targets. I was just wondering if you could talk about the competitive landscape at this point. Sure. It is a very fragmented market, as you point out, and that does create some, I think, some good open fields running for us. There aren't, as I said, this is kind of a rare platform investment. We don't generally comment on M&A just because it's very hard to project results there. It's something that we'd be open to, again, if we can get the right returns, but we think we've got a lot of opportunity to build this business organically. We think what we bring to the table in terms of competitive advantage is our existing network and our existing footprint. I would describe that not just in terms of the obvious physical assets, the pipelines and storage that we have, but also the customer access and customer contacts that we have that will enable us, I think, in some decent-sized chunks to develop and originate some additional business, really in both categories, the voluntary market as well as the transport market. We've got good project management expertise. We're actually looking at whether or not we can make some of the equipment that's being deployed in these areas. We think we bring a lot to the table. We're getting a good team as part of this acquisition. We think we can expand this business, expand it organically, and do it in a way that the returns are attractive. Got it. That's helpful. Thanks. Maybe just shifting to the Permian and gas takeaway, just wondering if you could update us there on thoughts. It seems the capacity is loose now with PHP online, Whistler soon to be online. If the Permian grows as some expect, there could be tightness in the next couple years, two to three years. I guess that timing really depends also on how much Mexican demand materializes. It seems like the long-awaited demand started to show up here. Just wondering if you could talk about those dynamics and I guess how you see Permian gas takeaway needs evolving over time. Yeah. We agree generally with your projection there, that we do think that the Permian, as it continues to fill up, and it is a very active area again, as you know, that there will be a need for yet another pipe to come out of there. Both our view of it as well as third-party views that we gather on this is that's probably mid-decade. Which means that you have to start the commercial conversations a couple years or maybe a little more ahead of that. We had pretty active conversations in that arena before. We know who to talk to about it. I wouldn't characterize those as super active right now, but we think they could as we get closer to tightening up the Permian. Got it. I'll leave it there. Thank you. Thank you. Our next question comes from Shneur Gershuni from UBS. Your line is open, sir. Hi, good afternoon, everyone. Maybe I'll start off on the guidance side. Definitely appreciate the color that you just provided to Jeremy's question. With respect to the guidance, it seems like it's raised by a couple of hundred million, and you sort of seem to indicating about meeting or exceeding the top end of the range. I was wondering if you could just sort of expand on the drivers on the change. I mean, obviously there's the Stagecoach acquisition that you mentioned. There's the RNG acquisition as well, but it doesn't seem to account for all of it. Is it something related to better expectations in your refined products business? Is it on the Natural Gas side? I'm just curious if you can give us a little bit of color on the elements involved in the guidance update. Yeah. The two primary factors other than the Stagecoach acquisition are improved refined products volumes from what we previously expected. As we said on the product side of the business, road fuel is now flat with 2019 compared to second quarter of this year versus second quarter of 2019. The other primary driver is higher commodity prices. I'm measuring, those are the primary changes against the high end of the guidance of $5.3 billion. Okay, great. Maybe as a follow-up question. Last quarter when you adjusted your guidance, you had sort of pulled forward the Ruby recontracting. In fact, I've sort of been thinking about the last three or four years, you've kind of had like a recontracting trend in the Natural Gas segment that's essentially resulted in lower contract ranges and so forth. That's been about $100 million-$200 million a year drag on EBITDA. Is that now substantially over? So all the growth- related projects that you're talking about on the Energy Ventures side and so forth, or any of the capital growth that you spend will in fact be additive to EBITDA from this point going forward? Just kind of curious if we're kind of done with the recontracting resets if maybe there's a little bit left, but is it substantially out of the way at this point? Yeah, we do see it being lower post-2021 and we update that, as you know, every January when we do our investor conference, and we'll do that again. We see it as being lower in terms of the roll-off post-2021. The background there is, I think you know well, is that 10 years ago or a little bit more, we built a number of pipelines that were kind of point-to-point pipelines, and they were built on the strength of long-term contractual commitments in a very high- basis environment. As you get to the end of those 10 or 10+ year contracts and they start to roll off, they're rolling off into a more challenged basis environment for those particular pipes. That has had the effect of kind of masking or dampening, however you want to see it, some of the, I think, strong underlying performance in our Natural Gas Pipelines segment. That's what's been going on, and as I said, I think we see that as being lower from here. In terms of your broader question, we invest all of our capital on a return. Each one stands on its own from a return standpoint. We've been getting good returns as we show in our performance update there. Very attractive returns on the capital that we've deployed. In terms of the overall puts and takes, though, there are puts and takes across a diversified asset portfolio like ours. Those puts and takes and the uncertainty around them in further out periods are hard enough to quantify or uncertain enough to quantify for me to give you a specific answer to your question about base business then plus, right? Generally what we do is give you the best view we can of the fundamental drivers underpinning our business economically and commercially so that our investors can come to their own expectations about that future. We don't guide beyond the current budget year or updates to the guidance like we're giving you today. We try to provide the transparency and particularly around the roll-off issue in particular, but we don't guide beyond the current year. Just to clarify, the roll-offs will continue for multiple years or are we approaching the end of it? There's still a couple of years to run. They're very modest after you get through this year. Quite modest. Okay. Got it. Okay, perfect. Thank you very much. Really appreciate the color today. Thank you. Next question comes from Spiro Dounis from Credit Suisse. Your line is open, sir. Thank you. Afternoon, everybody. Would like to start off with gas macro if we could. Would appreciate your all's thoughts on the environment here and what that could mean for the near and medium term. Specifically, just curious how sustainable you think this price environment is? I'm sure you're all talking to your producers and so curious what they're saying about their plans and activity for growth on the gas- directed side of things? Is there something incremental you could be doing here on the LNG side as well to capture even more of that market and more of that growth? Sure. I mean, overall on gas, the macro look on gas is we remain as others do bullish on U.S. natural gas. I think we see between now and 20 years from now, updated third-party analysis see growth in that market of about 23 BCF, or almost 24%. A pretty nice long runway. A lot of that is driven by exports. There's some industrial in there as well, but exports are a part of that picture. For our business, we've tried to distinguish ourselves with our customers as a storage provider and a transport provider and a good operating partner, to be able to capture as much of that business as we can. We have a very good share of that business moving through our pipes today, and we look to expand it. The map of where those facilities are coming in is lined up very nicely with our natural gas pipeline footprint. Just to put a little more context on it, as we look at, and this is a different timeframe now, 2020- 2030, the growth that we see in natural gas happening over that 10-year period, 80% of that is Texas and Louisiana, and a lot of that is the export market, and our assets are very well positioned for that. In terms of the current natural gas pricing and the sustainability of it and how our producers are responding to that, I'll ask Tom to comment a bit. Yeah, I mean, it's hard to predict the future, but I do think that given that the demand growth seems pretty clear that we're certainly going to have a tight market at least for the intermediate term. What we're seeing and hearing on the producer side is a measured response. I mean, definitely we're seeing an increase in activity. The rig growth has been certainly visible. I think there's also a strong financial discipline that we're seeing in the producer community that's I think going to make the supply side response a bit more delayed relative to what we're seeing on the demand side. I do anticipate a fairly tight supply-demand balance here for the next couple of years at least, and I think that means a higher- price environment. Got it. That's helpful. Thanks, Tom. If we could just go back to Kinetrex quickly. Sounds like the path forward or at least the base case is organic growth and not necessarily M&A, although I'm sure that remains an opportunity for you. As we're thinking about the returns on organic growth, I think the press release cited a less than 6x fully capitalized return on this project, plus the M&A. I think a lot of us took that to mean that organically you can do even better than that. Are we reading through it the right way? Are these 3x-4x return types projects? At some point, do those get competed away? I'm just curious how you're thinking about that component. Yeah. I don't want to get into specific returns. It is at least a potentially competitive environment out there. The returns that we're seeing are attractive for how we look at other deployments of capital in the expansion context. We make appropriate adjustment to those return hurdles based on the level of exposure to things like RINs. Okay? We need to do better where there's more RINs exposure. If we got secured firm long-term fixed prices, we can look at that a bit differently. They are good compensatory returns and we are happy to invest in these opportunities. Great. That's all I had. Thanks, Steve. Thanks, team. Thank you. Next question comes from Keith Stanley with Wolfe Research. Your line is open. Sorry to beat a dead horse on Kinetrex. I just want to confirm, are there any fixed price contracts in place today for the RNG sales? Then I guess bigger picture, can you talk a little more about the revenue streams for the business? You mentioned the RINs. Can you benefit from the Low Carbon Fuel Standard? Just other attributes? I'm trying to better understand the business. Then last part to that is just I'm assuming most of the EBITDA from this business that you're buying is from RNG sales and the existing LNG business is pretty small. Is that fair? I'm going to ask Anthony to answer. Yeah. On the last part of that, I think currently right now about 60% is from the RNG side of the business. The remaining piece from LNG. Once the three development plants are in service, it's closer to 90% RNG at that point in time. LNG is not decreasing over that point in time. It's just obviously the RNG component is increasing. Sorry remind me, Keith. Low Carbon Fuel Standard. Yeah. In order to capitalize on LCFS you need to establish a pathway. We haven't established a pathway for these specific facilities. They are under contract locally with a transportations provider and generating the RINs. You would have to sell that environmental attribute into California, establish the pathway. Quite frankly, the California market is really dominated from an RNG standpoint by really the dairy side of the industry because the carbon intensity scores are much lower. There's a much greater benefit for the RNG for LCFS as a result of that. I would think of it as terms of landfill is the market for it is really outside of the California market. And then fixed price, you're variable today. Yeah. There's a certain part of the LNG offtake which is take or pay currently. The RNG that's going to be sold into the CNG market with the three development plans is effectively at an index price. Got it. Thanks a lot. That was very good color. Second question, I know the first was long-winded there. You positioned it pretty well that Stagecoach adds to the core gas pipeline business and Kinetrex gives you this platform for growth in a new and exciting area. Strategically, would you be open to maybe looking to selling down some of, call it your less core businesses, whether that's refined products pipelines and terminals, crude, or other areas with less scale as sort of a source of funds to continue this strategy where you're putting money into the core gas business and into some of the energy ventures? We like the portfolio of assets that we have today. Having said that, we say what we always say, everything is for sale at the right valuation. If someone can make more of a particular investment that we have than we can, then we'll consider that. We did a bit of a sell-down on NGPL. We continue to operate it and continue to like our position in that asset. We got good value there. We do look at those things. I think we've done a good job, particularly in John Schlosser's Terminals business, kind of pruning assets to stay focused on the things that we really do well over the years are kind of our hub positions and the like. There's not a have to sell on anything, and we like the portfolio that we have today, but at the right price, we would transact. Thank you. Thank you. Our next question comes from Tristan Richardson from Truist Securities. Your line is open, sir. Hi. Good afternoon, guys. I think it may have been pre-pandemic when you last discussed possible incremental investment in SACROC expansion that might be more chunky type of CapEx. Is the municipal approvals you noted sort of a precursor to that type of expansion that you had discussed back then, or can you sort of remind us the potential size and scope of this project? Yeah. What we did that is talked about in the release today is we aggregated some rights to do further development. We did it in a place that is geographically adjacent to the SACROC unit, and we got approval to incorporate it into the unit. There's advantage to that in that we think we have good insight into the geology by buying up the rights. We entered it in a fairly cost-effective way. We have good facilities at SACROC that let us do economic expansions there. It's a nice opportunity for us, and we continue to look at that as well as additional incremental investments within the existing unit along the way. Jesse, anything you want to add? Think you got it. Okay. Thanks, Steve. In an earlier question, you talked about the gas macro, but curious maybe on the midstream side. Obviously Kim noted that the Eagle Ford remains competitive, but clearly seeing improved activity at Hiland. Does the view on midstream accelerate into the second half based on what you're hearing from customers? You kind of need to look asset by asset. You're right. We've got some good performance happening on Hiland. We're expecting to see some incremental performance based on the gas price dynamics that Tom mentioned in the Haynesville as well. That's come slower than what we expected, but I think it's coming. Just overall, in the broader picture, natural gas midstream infrastructure, our pipeline network and our storage network continues to attract good value. Coming out of the winter storm, for example, not just in Texas, but really along our system, we've successfully transacted for incremental and also attractive, that is increasing renewal rates, particularly on our storage assets, especially in Texas, but also elsewhere on our system. It was a bit of a, I think, a wake-up call to the market generally that there is real value in having that delivery flexibility and real value in holding firm transport capacity. I think just overall, we are seeing uplift, if you will, in that area. Thanks, Steve. Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open. Hi, good afternoon. I guess I will ask one on CCUS since no one has yet. The way I understand it, the most near-term opportunity is taking CO2 from Permian processing plants and putting it into your existing CO2 infrastructure for EOR. Can you give some sense of just the timing of this potential opportunity? Basically, how long does it take to install the equipment and physically connect one of these plants, and what is the sense of urgency that you're hearing on this from processors? Yeah, I'll start and then I'll ask Jesse to comment more specifically on the deal front. You made the right point in your opening on the question, which is that the near-term opportunity really is along existing infrastructure and primarily processing and also ethanol plants because the CO2 stream is pure or fairly pure there, and so it still needs to be compressed and get it into the pipe, et cetera. The other thing about it is the pipe itself, right? The CO2 moves most efficiently in a liquid state, which means high pressure, so that's 1,800-2,200 PSI. What that means is you're not going to repurpose a lot of gas pipe or oil pipe for that, for example, when you tend to operate in call it 600 PSI to maybe 1,450 PSI on the newer gas pipes. So that is then a barrier, right? If you've got to build new heavy wall pipe in order to get it to a place where you can sequester it, that's a barrier. EOR is a valuable application of that CO2, that does make that the near-term opportunity. Having said that, I'll ask Jesse to comment on timing and current deal activity. In the Permian, there are several operators that we are in discussions with currently. Timing, you're probably looking at 12-18 months if it goes into EOR. EOR permits are in place, and you can go in, albeit at a lower credit. If it's sequestration, you're looking at much longer horizon because you'll need a Class VI well permit, which currently the EPA has authority over. There's only a couple of these in place throughout the United States, so that's probably more of a three- to five-year timeframe in obtaining one. That's current today. An EOR, that could be taken, I would suspect, within the next 12-18 months. Great. Can you comment on the sense of urgency any further? Yeah. There's a lot of interest. Obviously, the credits were clarified earlier in the year. The rules of engagement are there and the economic decisions are being made. There is a lot of interest. The moving into the FID stage and ordering equipment, like I said, it's probably a good year to 18 months away. Great. That's all for me. Thank you. Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Your line is open. Hey, guys. Thanks for taking my question. Actually, two of them totally unrelated from each other. First of all, I know you addressed the potential need for Permian takeaway, how are you guys thinking about the need for Haynesville incremental takeaway, and whether you think the Haynesville's starting to get tight from basically taking it out of the basin and either to the southeast or straight down to the Gulf? That's question one. Question two is a follow-up one. Somebody earlier asked a little bit about the asset mix and asset disposals, Steve, I think you made the comment about everything for a price. Well, where does Elba fit into that? It seems like the infrastructure funds market or others are paying pretty healthy multiples for minority stakes in contracted LNG facilities. Just curious, is there anything that would keep Elba off that table or your stake, or do you view that as super core to the business? Well, I'll start with Elba, and I'll have Tom comment on Haynesville. You may recall —actually, this I think predates you covering us, but we did sell down an interest in Elba when we were post-contract but still developing it, and we did that. It was an attractive valuation for us, and it helped share the capital burden. We've kind of done that move, if you will, already. In terms of how it fits in the overall portfolio, it is integrated with our broader system. We have the Elba Express Pipeline which we have opportunities on as well. We have the potential to do more at Elba in terms of storage and the like. It's interconnected with our SNG system. It fits nicely within the portfolio of assets we have. As you know, it's under a long-term contract with Shell which is an attractive credit and risk profile for us. Very long-term contract with Shell, it fits very well. We did a partial sell-down earlier, as I mentioned. Tom, on the Haynesville takeaway need. Yeah. I think given the increase in gas prices and the activity that we're seeing in the Haynesville, I think there's a real possibility that there will be additional Haynesville takeaway necessary. I think to my point that I made earlier, I think producers are really wanting to have sustainable prices at these higher levels before they're, I think, living within their means, managing their balance sheets appropriately. I think the activity is definitely increasing. I think if we see sustained gas prices and additional activity in the Haynesville, there will be three to five years, probably closer to a three-year timeframe, there may be a need for additional capacity out of that market. Got it. Thank you, guys. Much appreciated. Thank you. Our next question comes from Becca Followill with U.S. Capital Advisors. Your line is open. Hi, guys. Two questions. One minor. In the non-recurring items, there's legal and environmental and other tax charges that you've had back in of $28 million and i t was $84 million in Q1, so $112 million. Can you talk about what's in there? Do you expect more of that as we go into the rest of the year? This is in the non-recurring items, Becca? Right. If you want, I can ask another question while you're looking that up. Go ahead. Okay. I could already tell. Been in your shoes. The other side is kind of a variation on what Tristan asked is, CO2, we've got oil prices now back close to $70, which is probably pretty attractive economics, I assume, for that business. Are you anticipating maybe ramping CapEx back up in that business? And is there any way to stem some of the more significant declines that we've seen of late as you backed off on spending? We'll continue to look at that like we always have, Becca, which is we'll look at it on an individual project basis, and we make our assumptions around crude price. It does uncover the potential for more projects to become economic, and we've got a couple that we're working on right now at both SACROC and Yates that are incremental. We'll continue to look for those. It's true, we are experiencing year-over-year declines in that production, but we are 5% above our plan, and that is better performance from some of our SACROC developments as well as a lesser decline rate than what we expected on some previous developments. Doing well versus our plan and continuing to invest opportunistically as we always have. Okay, let me sneak one more in while he's looking for that number, is just what commodity price is assumed in guidance now? $70 and $3.50. $70 on crude and $3.50 on gas for the back half of the year. Got you. Thank you. Okay, on your questions with regard to the certain items, legal and environmental reserves, that's exactly what it is. Just additional legal and environmental reserves. In the first quarter, it was mostly some legal reserves with regard to a dispute that we have outstanding. We're getting a little closer to settlement, so we took a reserve there. We also took some reserve for incremental environmental impact cost estimates that we have. In the second quarter, in this current quarter, it was related to a rate case reserve item that we've adjusted now that we have more information. These things are hard to call and come up sporadically. I don't think that this is something that you'd anticipate recurring on a regular basis, but they come up sporadically. Great. Thank you. Thank you. Our next question comes from Christine Cho with Barclays. Your line is open. Hi, everyone. I just have one question. Historically, you guys have included debt repayments at your equity investment in your CapEx. As we look to 2022 and try to think about and calculate free cash flow generation, with the Ruby Pipeline debt coming due in first half of next year, how should we be thinking about that? That's right, Christine. We typically do, and we've done that in the years past where we had large known debt maturities coming due where we knew we were going to be making a contribution for our share of that maturing debt at unconsolidated JVs. I think with the ongoing conversations that we're having with our partner at Ruby, I think the determination of what we're going to put in the budget is to be determined. If we plan to fund our share of it'll be part of the use of cash that we expect for next year. I just want to make the point here, as we've done for multiple quarters now, we are working with our partners, and we will be making an economic decision on this asset. Do you have a timeframe on when exactly? No, we're not the only person at the table. Okay. Can't believe that. Okay, thanks. Thank you. Our next question comes from Pearce Hammond with Piper Sandler. Your line is open. Good afternoon. Thanks for taking my questions. You have a great slide in your deck, slide 24, that details the current estimated U.S. carbon capture cost with ethanol on the low end, and on the high end, natural gas, and then a comparison with the 45Q tax credit. That's a helpful slide. My first question is, are you hearing anything in Washington about maybe boosting the 45Q above that $50 a ton for non-EOR? Yeah, there is some discussion around that, because I think people are excited about incenting that activity, and I think people believe that part of the solution here on greenhouse gas emissions is going to have to involve continued use of hydrocarbons and also carbon capture just generally. I think there is interest in doing that and expanding that. As Jesse pointed out, we just did get the final regs on the 45Q, and so that's out there and available to us to use today, but I think it will continue to be a part of the conversation. Predicting where that will come out, I will not even venture a guess. Steve, thank you for that. As a follow-up, I know natural gas power plants, combined cycle power plants, are listed on the high end of the carbon capture cost in your graphic, are you seeing interest? Is the phone ringing from some of the big companies, like the big combined cycle power companies? Are they interested in CCS? Very preliminary conversations with one of our power customers. I would just say very preliminary. Definitely more interest from the ethanol side? It's just more within reach on the ethanol and the gas processing side for the reasons that you pointed out. Great. Thank you very much. Thank you. Next question comes from Michael Blum with Wells Fargo. Your line is open. Thanks. Good afternoon, everyone. Wondering, just in light of the acquisitions you've made this quarter, both on the Energy Transition side and obviously Stagecoach, just how you're thinking about where buybacks kind of fit into the mix in terms of capital allocation and clearly this quarter it seems like you prioritized acquisitions. Just want to get your thoughts on all that. Well, we've said repeatedly that we think we're good stewards of the cash flow we're producing, and we've said repeatedly we want to maintain a strong balance sheet. We will look for acquisitions if they meet our targeted returns. In this case, both of these did, and we believe are very strategic to us. We intend to continue to pay a good dividend or raising the dividend. Then we'll look opportunistically at the opportunity to repurchase shares. We're looking at all those in concert. So it just depends on what the opportunities are. Okay, got it. I guess my other question is on Stagecoach. You made some interesting points about why you think storage rates are going to increase over time. My question is, what is your ability going to be to capture that in that asset? What does the contract position look like roughly so that as rates do go higher, you're able to capture that? Thanks. The average contract life on that asset is about three years. It's kind of split right now. About 50% of that is with utilities and end users. The other 50% is predominantly producers, but includes some marketing firms as well. That's the general contractual timeframe. Look, we can look at doing short-term transactions and other things. A combination of TGP and that asset unlocks some other potential commercial opportunities which are incremental to what Stagecoach could have done on a standalone basis. The rates for Stagecoach services are market-based rates as well. Perfect. Thank you so much. Thank you. Next question comes from Jeremy Tonet with JP Morgan. Your line is open. Hi. Thanks for letting me sneak one more in. Just wanted to touch on carbon sequestration real quick. If the Texas Railroad Commission is successful in, say, the next year or so, getting primacy, just wondering how you think that might impact the timelines of Class VI wells, such as what happened with Wyoming and North Dakota. Do you think that the wells, there's a greater chance that it's offshore, onshore, just given offshore being more costly but having benefits such as the rights with space, pores, what have you? Just wondering your thoughts on sequestration development. Yeah. It will shorten up the timeframe if the Texas Railroad Commission is in charge of it. Now there's a process you kind of alluded to there. The Texas legislature in this last session did what it needed to do to set the Railroad Commission up to go seek primacy. They have to go put their plan together and put that on file, which could be this fall. I don't know how long it will take the EPA necessarily to act. Once it acts and the Railroad Commission has control of it, I think they're going to process them very quickly. Jesse made the point earlier, the permitting process itself is today at the EPA, is just very slow. Now, I would think that they are going to want to, as a public policy matter, speed it up anyway, right? It's five or six years right now. That doesn't work. Whether it's the EPA speeding itself up in order to enable more of this for its own policy objectives, or whether it's the Railroad Commission getting control of it will get sped up. In terms of onshore versus offshore, we're obviously onshore focused in the opportunity that we have and given what our footprint of existing pipeline network is, which is a very important consideration for the reasons I said earlier. Jesse, do you have any other comments on onshore versus offshore? I agree the surface ownership price is important, but there are opportunities onshore as well where you have common ownership. Looking at both, but more cost effective to do onshore at this point. The common ownership between the surface- Surface and mineral. Yeah. Got it. Thank you. Thank you. Our next question comes from Colton Bean with Tudor, Pickering, Holt & Co. Your line is open. Thanks. Just one on my end. A lot of questions on RNG and CCS. As we look at the concentration of CO2 and biogas coming off the landfill, is there an opportunity to integrate carbon capture with landfill RNG over time? Yeah, there's certainly an opportunity. It's going to be a scale issue. These RNG facilities are relatively small at the plants themselves. Depending on the growth and the size of the emission it'll be challenging, but there is an opportunity. Yes. Thank you. There are no further questions in queue at this time. Okay. Well, thank all of you for listening to us and have a good evening. That does conclude today's conference. You may disconnect at this time, and thank you for joining.