Welcome to 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. Please make sure your phone is unmuted and state your name and company clearly when prompted. I would now like to turn the call over to Mr. Richard 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 were released today. This call includes forward-looking statements within the context of the Private Securities Litigation Reform Act of 1995 and the Securities and 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 reviewing 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 clear 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 is 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. And 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, which we purchased 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 miles of pipeline. We're excited about this transaction for several reasons. As we discussed in 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, which we put 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 6 times 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 RIN's value. You don't make money on the gas sale. Now, 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 RIN obligations as well. D3s are for advanced biofuels and 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 will have the opportunity to mitigate our exposure to RIN 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. So, 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 mentioned transacting on attractive returns for our shareholders, not loss leaders and not doing things for show. This deal is a great example of that, and 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. So very good progress in a short period of time. These two deals illustrate a couple of key 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. And with that, I'll turn it over to Kim.

Okay. Thanks, Steve. First, I'm going to start with our business fundamentals, and 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 dekatherms per day versus the second quarter of 2020, and 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 then higher deliveries to our Elba Express LNG facility. These increases were partially offset by lower volumes on CIG due to declines in Rockies production and Fayetteville Express contract expirations. Physical deliveries to LNG off of our pipelines averaged approximately 5 million dekatherms 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 is 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 for 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 '20. For gathering volumes though, I think the more informative comparison is the sequential quarter. So, compared to the first quarter of this year, volumes were up about 6%. And here we saw nice increases in Hiland volumes, which were up about 10%, and the Haynesville volumes, which reports were up about 13%. In our Product Pipeline segment, refined products were up 37% for the quarter versus the second quarter of '20. Volumes are also up about 17% versus the first quarter of this year, so we saw substantial improvement both year-over-year and quarter-over-quarter. Compared to the pre-pandemic levels, using the second quarter of 2019 as the reference point, road fuels, which include gasoline and diesel combined, are essentially flat. Jet fuel is still down about 26%. Crude and condensate volumes were up 6% in the quarter, versus the second quarter of '20, 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 the required inspections, approximately 98% of our tanks are leased. Most of the revenue we receive comes from fixed monthly charges for tanks under lease. We also 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. However, that still remains below 2019 by about 6% on total liquids volumes, and 5% when focusing solely on 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%, 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, in terms of NGL prices, did offset some of the volume degradation. However, if compared to our budget, we're currently anticipating that oil volumes will exceed our budget by approximately 5%, 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 witnessing increased gathering volumes in the Bakken and the Haynesville, along with a nice recovery of refined products volume. Crude oil volumes are above our expectations in our CO2 segment, and we're receiving some price help. While we still experience some weakness in our Jones Act tankers, the Eagle Ford remains highly competitive. Now, 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 provided last quarter. The range we provided last quarter was $5.1 to $5.3 billion. The outperformance versus the high-end range is driven by our Stagecoach acquisition, higher commodity prices, and better refined product volumes. And 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 a $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. So 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 onto the segment EBITDA and distributable cash flow performance, our natural gas segment was up $48 million for the quarter, primarily due to favorable margins in our Texas Intrastate business, greater contributions from our PHP asset, which is now in service, along with an increase in 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 product 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 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 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. And 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 taken in 2020 as a result of the pandemic. Just timing and 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, but 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 3.8 times debt to EBITDA, which is down nicely from a 4.6 times 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 we provided in the first quarter. For debt to EBITDA, we expect to end the year at 4.0 times. That includes the acquisitions of Stagecoach, which we closed on July 9th, and Kinetrex, which we expect to close in the third quarter. Our year-end debt to EBITDA level has the benefits of the largely non-recurring EBITDA generated during winter storm Uri earlier in the year, and our longer-term leverage target of around 4.5 times has not changed. To reconcile our net debt, the net debt for the quarter ended at about $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 $1.25 billion of DCF, paid out approximately $600 million of dividends, spent approximately $100 million of growth capital and contributions to our joint ventures, and had a $175 million worth of working capital sourced from cash flows, primarily interest expense accrual. That explains the majority of the change for the quarter. For the change year-to-date, we've generated $3.354 billion of distributable cash flow, spent $1.2 billion on dividends, spent $300 million in growth Capex and JV contributions, received $413 million on our partial interest sale of NGPL, and 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. And just a reminder to everyone as a courtesy to the others on the call, we ask that you limit your questions to one and a follow-up, and 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, please ensure that your phone is unmuted and record your name and company when prompted. Our first question comes from Jeremy Tonet from JPMorgan. Your line is open.

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? And 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 types of targets. Just wondering if you could talk about the competitive landscape at this point?

Sure, it is a very fragmented market, as you pointed out, and that does create some good open fields running for us. There aren't as many players in this space compared to the traditional sectors. 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 opportunities to build this business organically. And we think what we bring to the table in terms of competitive advantage is our existing network and our existing footprint, and 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 will enable us to develop and originate some additional business in decent-sized chunks, both in the voluntary market as well as the transport market. We’ve got good project management expertise and are actually looking at whether or not we can make some of the equipment that's being deployed in these areas. So we think we bring a lot to the table. We're getting a good team as part of this acquisition, so we think we can expand this business, expanding it organically and doing it in a way that the returns are attractive.

Got it. That's helpful, thanks. And then maybe just shifting to the Permian and gas takeaway, just wondering if you could update us on that. It seems the capacity is loose now with PHP online, Whistler soon to be online, but if the Permian grows as some expect, there could be tightness in the next couple of years, two to three years, but I guess that timing really depends also on how much Mexican demand materializes. And it seems like the long awaited demand started to show up here, so just wondering if you could talk about those dynamics and how you see Permian gas takeaway needs evolving over time?

Yes, I agree generally with your projection there. We do think that the Permian, as it continues to fill up, will have a need for yet another pipeline to come out of there. Both our view of it and third-party views we gather foresee that need probably mid-decade, which means you have to start the commercial conversations a couple of years or maybe a little more ahead of that. We had pretty active conversations in that area before. We know who to talk to about it. I wouldn't characterize those as super active right now, but we think they could pick up as we get closer to a tightening in the Permian.

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. I definitely appreciate the color you provided to Jeremy's question. But with respect to the guidance, it seems like it raised by a couple hundred million and sort of seemed indicating about meeting or exceeding the top end of the range. I was wondering if you can just sort of expand on the drivers of the change. Obviously, there's the Stagecoach acquisition 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 product volumes from what we've previously expected. And as we mentioned on the product side of the business, fuel is now flat with 2019 when comparing the second quarter of this year versus the second quarter of 2019. Additionally, the other primary driver is higher commodity prices, and those are the primary changes against the high end of the guidance of $5.3 billion.

Okay, great. As a follow-up question, last quarter when you updated your guidance, you advanced the Ruby recontracting. I've been reflecting on the past 3 or 4 years, during which you have seen a recontracting trend in the Natural Gas segment, leading to lower contract ranges. This has been causing a drag on EBITDA of about 100 million to 200 million a year. Is that now largely resolved, meaning that the growth-related projects you're discussing in the energy venture side will indeed contribute positively to EBITDA from now on? I'm curious if we have moved past the recontracting resets, or if there is still a bit remaining, but is it mostly out of the way at this point?

Yes, we expect it to be lower after 2021. We provide updates every January during our investor conference, and we will do so again. We anticipate a decline in the roll-off post-2021. The context is that around ten years ago, we established several point-to-point pipelines based on long-term contractual commitments in a high-basis environment. As these contracts, which last for more than ten years, come to an end, they will transition into a more challenging basis environment. This situation has concealed some of the strong underlying performance in our Natural Gas Pipeline segment. While I can't provide exact details on roll-offs in the coming years, they will be more modest after this year. Generally, we invest all our capital with a focus on returns, with each investment standing on its own in that regard.

Just to clarify, the roll-offs will continue for multiple years or are we approaching the end of it?

There is still a couple of years to run, but they're very modest after you get through this year. Quite modest.

Okay. Got it. Okay. Perfect. Thank you very much. We 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. I would like to start off with Gas Macro, if we could. Would appreciate your thoughts on the environment here and what that could mean for the near-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?

The overall macro look on gas is that we remain bullish on U.S. natural gas. Between now and 20 years from now, updated third-party analysis sees growth in that market of about 24%, which is a nice long runway. A lot of that is driven by exports and some industrial applications as well. For our business, we've tried to distinguish ourselves with our customers, as storage providers and transport providers, to capture as much of that business as possible. We see good share of that business moving through our pipes today and we aim to expand it. The map of where those facilities are coming is aligning very nicely with our natural gas pipeline footprint. As pointed out, from 2020 to 2030, growth in natural gas will be concentrated in Texas and Louisiana, particularly driven by exports, and our assets are well-positioned for that. In terms of current natural gas pricing and how sustainable it is, it's hard to predict the future, but with the demand growth we see, we anticipate a tight market in the intermediate term. While we are seeing increases in activity, producers seem to be taking a measured approach in their responses. This balance may lead to a higher price environment.

Got it. And that's a double next time. And then, if you could just go back to Kinetrex quickly, it sounds like the path forward or at least the base case is organic growth without necessarily pursuing M&A, although it remains an opportunity. As we think about organic growth, I believe the press release cited a less than 6 times fully capitalized return on this project plus the M&A. So, I think many took that to imply you could do even better with organic growth. Are these 3 to 4 times return-type projects? At some point, will those get computed away? I'm curious how you're viewing that component.

I don't want to get into specific returns. It is at least a potentially competitive environment out there. However, the returns we're seeing are attractive when we compare them with other capital deployments in our expansion context. We adjust our return hurdles based on the level of exposure to things like RINs. We need to do better where there's more RINs exposure, and if we have secured, firm, long-term fixed prices, we can view that slightly differently. We find that they provide good compensatory returns, and we are happy to invest in these opportunities.

Great. That's all I had. Thanks, Steve. Thanks for your support.

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? 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 in China? I want to better understand the business. Lastly, I'm assuming most of the EBITDA from this business that you're buying is from RNG stills and the existing LNG business is pretty small. Is that fair?

I would ask Anthony to answer.

Currently, about 60% is from the RNG side of the business, and the remaining piece is from LNG. Once the redevelopment plans are in service, it's closer to 90% RNG at that time. LNG is not decreasing during that period; it's just that the RNG component is increasing. In order to capitalize on the Low Carbon Fuel Standard, you need to establish a pathway. We haven't established a pathway for these specific facilities, they are under contract locally with a transportation provider. To capitalize on RINs, you need to settle that environmental attribute. The California market has been dominated by the RNG industry due to lower carbon-intensity scores, leading to a greater benefit for RNG in this regard. The market for it is really outside of the California area.

Is the pricing fixed or variable today?

Yes, there's a portion of LNG uptake that is market variable currently. The RNG going into the CNG market with the 3 development plants 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. 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 selling down some of your less core businesses, whether that's refined products pipelines and terminals, crude, or other areas with less scale, as 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, and we continue to operate it and like our position in that asset. We got good value there and look at those options. However, I think we've done well, particularly under John Schlosser in pruning assets to stay focused on the things that we really do well and maintain hub positions over the years. There's not a need to sell anything, as we like our portfolio today. But at the right price, we'll definitely transact.

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 require more Capex. Is the municipal approvals you noted a precursor to that type of expansion that you had discussed back then, or can you remind us of the potential size and scope of this project?

What we did that is talked about in the release today is we aggregated rights to do further development. We did it in a place that is geographically adjacent to the SACROC Unit, and we received approval to incorporate it into the unit. There’s advantage to this approach, as we believe we gain good insight into the geology. By acquiring the rights, we proceeded in a cost-effective manner. We have good facilities at SACROC that allow us to make economic expansions. It's a nice opportunity for us, and we continue to explore that as well.

I 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 in the second half based on what you're hearing from customers?

You need to look asset by asset. You're right. We have some really 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 has come slower than we expected, but I believe it's coming. Overall, our natural gas midstream infrastructure, our pipeline network, and our storage network continue 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 attractive rates. Particularly on our storage assets, especially in Texas, this period served as a wake-up call to the market about the value of having delivery flexibility and real value in holding firm transport capacity. We're seeing that uplift in this 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 existing CO2 infrastructure for EOR. Can you give some sense of the timing of this potential opportunity, that is, how long does it take to install the equipment and physically connect one of these plants? What is the sense of urgency that you're hearing on this from processors?

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 long 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 into the pipe, etc. The other aspect of it is the pipe itself. The CO2 moves most efficiently in a liquid state, under high pressure—1800 to 2200 PSI. This means that repurposing a lot of gas pipe or oil pipe may not be feasible since they typically operate at lower pressures. So, that has been a barrier. EOR is a valuable application of that CO2, making it a worth while endeavor. Having said that, I will ask Jesse to comment on the timing and current deal activities.

In the Permian, several operators are currently in discussions with us. Timing is 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 horizons because you'll need a Class VI well permit, which currently the EPA oversees. Only a few of those are in place throughout the United States, so that's probably more of a 3-5 year timeframe for obtaining one. For EOR, that could be initiated in the next year to 18 months.

Great. Can you comment on the system urgency any further?

There is a lot of interest. The credits were clarified earlier in the year, so the rules of engagement are set, and economic decisions are made. There is a lot of interest moving into the FID stage in order and equipment, as I said, 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, and totally unrelated from each other. First of all, I know you addressed the potential need for Permian takeaway. But how are you guys thinking about the need for Haynesville takeaway, and whether you think the Haynesville is starting to get tight from basically taking it out of the basin and either to the Southeast or straight down on the Gulf? That's question one. Question two is a follow-up. 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 the Elba fit into that? Because it seems like the infrastructure funds market, where others are paying pretty healthy multiples for minority stakes in contracted LNG facilities. Just curious if there’s anything to keep Elba off that table or if you view that as super core to the business?

I'll start with Elba and then ask Tom to comment on Haynesville. You may recall—it might predate your coverage of us—but we did sell down an interest in Venmo when we were post-contract but still developing it. That was an attractive valuation for us and helped share the capital burden. So we've made that move already. Regarding its fit in the overall portfolio, it’s integrated with our broader system. We have the Elba Express Pipeline which offers us a lot of opportunities as well. We have the potential to do more at Elba in terms of storage and the like, and it’s interconnected with our SNG system. It fits very well and is under a long-term contract with Shell, which is very attractive from both a credit and risk profile. It fits well within our portfolio as we did partake in a partial sell-down earlier, as I mentioned. Tom, on the Haynesville takeaway needs.

Given the increase in gas prices and the activity we see in Haynesville, there's a real possibility that additional Haynesville takeaway will be necessary. Producers are looking for sustainable prices at these higher levels before increasing activity. They are managing their balance sheets appropriately and the increased activity is definitely visible. If we see sustained gas prices, there may be a need for additional capacity out of that market in the next few years.

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 got it back in a 28 million, and it was 84 million in Q1, so 112 million. Can you talk about what's in there, and do you expect more of that as we go into the rest of the year?

Visiting the non-recurring items, Becca.

Right. And if you'd prefer, I can ask another question while you're looking that up.

It's okay. Go ahead.

Okay. I could already tell, then you'll shoot. The other side—it’s a variation on what Tristan asked. With oil prices now close to $70, which is probably very attractive economics, are you anticipating maybe ramping Capex back up in that business? Is there any way to stem some of the more significant declines that we've seen of late as you had backed off on spending?

Yeah, we will continue to evaluate that like we always have, Becca. We look at it on an individual project basis and make assumptions around crude price. It has uncovered the potential for more projects to become economic. We have a couple that we’re currently working on at both SACROC and Yates that are incremental. We’ve been experiencing year-over-year declines in production, but we are 5% above our planned levels. This is due to better performance from some of our SACROC developments, as well as a lesser decline rate than what we expected on some prior developments. Therefore, we are doing well against our plans and continue to invest opportunistically as usual.

Okay. Let me sneak one more in while he's looking for that number. It's just, what commodity price is exchanged in guidance now?

$70 and $3.50. So $70 on crude and $3.50 on gas for the back half of the year.

For the balance of the year.

Got you. Thank you.

On your questions regarding certain items, legal and environmental reserves—this is exactly what it is: additional legal and environmental reserves. In the first quarter, it was primarily legal reserves regarding a dispute that we have outstanding. As we're getting closer to settlements, we took a reserve there and also took some reserves for incremental environmental impact cost estimates that we have. In the second quarter, the current quarter, it was related to a rate case reserve item that we've adjusted with more information. These things are hard to predict and come up sporadically, so I don't think we'd anticipate recurring expenses on a regular basis, but they can arise unexpectedly.

All right. 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 all had included the repayments of your equity investments in your Capex. As we look to 2022 and try to think about and calculate free cash flow generation, with the Ruby Pipeline debt maturing in the first half of next year, how should we be thinking about that?

That's right, Christine. We typically do. We've done that in past years where we had large known debt maturities coming due. If we have to fund our share of it, it will be part of the use of cash that we expect for next year.

I just want to reiterate that we are working with our partners and will be making an economic decision on this asset.

Do you have a timeframe on when exactly?

We're not the only party at the table, so we can't confirm that.

Okay. Thanks.

Thank you. Our next question comes from Pearce Hammond with Piper Sandler. Your line is open.

Good afternoon and thanks for taking my questions. You have a great slide in your deck, Slide 24, that details the current estimate of U.S. carbon capture costs with ethanol at the low-end and on the high-end natural gas. Then a comparison with the 45Q tax credit. That's a helpful slide. My first question is, are you hearing anything in Washington about possibly boosting the 45Q above the $50 a ton for non-EOR?

Yes, there is some discussion around that. I think people are excited about incentivizing that activity since carbon capture is recognized as part of the solution for greenhouse gas emissions that involves continuing hydrocarbons. However, predicting where that will come out, I cannot venture a guess.

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 costs in your graphic. But are you seeing interest—are the big companies like big combined cycle power companies interested in CCS?

We've had very preliminary conversations with one of our power customers, but I would just label those as initial discussions.

But definitely more interest on the ethanol side?

That's more accessible on the ethanol and the gas processing side, for the reasons you've 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. I'm wondering, just in light of the acquisitions you've made this quarter, both on the Energy Transition side and obviously Stagecoach, how you're thinking about where buybacks fit into the mix in terms of capital allocation? Clearly, this quarter it seems like you've prioritized acquisition, so just want to get your thoughts on all that.

We've stated repeatedly that we think we're good stewards of the cash flow we're producing. We aim to maintain a good balance sheet while looking for acquisitions that meet our targeted returns. Both of these acquisitions did meet our criteria and are very strategic for us. We plan to continue to pay a good and growing dividend, and we will opportunistically consider share repurchases as well. We assess all these elements in concert with one another, so it depends on the opportunities available.

Okay. Got it. As a follow-up, you made some interesting points about why you think storage rates will increase over time. My question is what is your ability to capture that in that asset? What does the contract position look like roughly so that as rates do go higher, you'll be able to capture that?

The average contract life for that asset is about three years. It’s roughly split right now: about 50% of it is with utilities and end-users, and the other 50% predominantly with producers but including some marketing firms as well. This is the general contractual timeframe. We can look at doing short-term transactions and other things. A combination of TGP and that asset unlocks some other potential commercial opportunities that would be incremental to what Stagecoach could have done on its own. The rates for Stagecoach services are market-based rates as well.

Perfect. Thank you so much.

Thank you. Next question comes from Jeremy Tonet from JPMorgan. Your line is open.

All right, thanks for letting me speak one more time. I 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 for Class VI wells such as what happened with Wyoming and North Dakota? Also, do you think the wells have a greater chance of being offshore or onshore, given offshore being more costly, but having benefits like rights for space, ports, and what have you? I was just curious your thoughts on sequestration development.

It will shorten up the timeframe if the Texas Railroad Commission is able to handle it. They have a procedure ahead, as you noted. The Texas legislature did what was necessary this past session to set the Railroad Commission up to seek that primacy. After that, they need to assemble their plan and file it, likely happening this fall. Once that happens, it's hard to predict how long it will take the EPA to act. However, I believe once the Railroad Commission has control, they will process it quickly. Jesse made the point previously that the current permitting process led by the EPA is quite slow, taking around 5 or 6 years now, which isn't functional. I do feel pressure will be on the EPA to speed it up to achieve policy objectives. Whether through EPA's initiative or the Railroad Commission obtaining control, expect the timeline to shorten. In terms of onshore versus offshore, we naturally look onshore for opportunities, largely based on our existing pipeline network, which is a significant consideration.

Yeah, I agree. The surface ownership rights are important here, but we also have onshore opportunities where common ownership exists.

Got it. Thank you.

Thank you. Our next question comes from Colton Bean with Tudor, Pickering, Holt & Company. Your line is open.

Thanks. Just one on my end. A lot of questions on RNG and CCS. As you 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?

Yes, there’s certainly an opportunity. However, the scale will prove challenging, as these RNG facilities are relatively small at the plants. Still, there's potential.

Thank you.

Thank you. There are no further questions in queue at this time.

We 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.