Kinder Morgan Inc (NYSE: KMI) Q2 2021 earnings call dated Jul. 21, 2021.
Corporate Participants:
Richard D. Kinder — Executive Chairman
Steven J. Kean — Chief Executive Officer
Kimberly Allen Dang — President
David P. Michels — Vice President and Chief Financial Officer
Anthony B. Ashley — Vice President of Energy Transition Ventures
Jesse Arenivas — President of CO2 & President, Energy Transition Ventures
Tom Martin — President, Natural Gas Pipelines
Analysts:
Jeremy Tonet — J.P. Morgan — Analyst
Shneur Gershuni — UBS — Analyst
Spiro M. Dounis — Credit Suisse — Analyst
Keith Stanley — Wolfe Research — Analyst
Tristan Richardson — Truist Financial — Analyst
Jean Ann Salisbury — Sanford C. Bernstein & Co. — Analyst
Michael Lapides — Goldman Sachs — Analyst
Becca Followill — U.S. Capital Advisors — Analyst
Christine Cho — Barclays — Analyst
Pearce Hammond — Piper Sandler — Analyst
Michael Blum — Wells Fargo — Analyst
Colton Bean — Tudor, Pickering, Holt & Co. — Analyst
Presentation:
Operator
Welcome to the Kinder Morgan’s Quarterly Earnings Conference Call. Today’s call is being recorded. If you have any objections, you may disconnect at this time. [Operator Instructions]
I would now like to turn the call over to Mr. Richard Kinder, Executive Chairman of Kinder Morgan. Thank you, sir. You may begin.
Richard D. Kinder — Executive Chairman
Thank you, Missy. Before we begin, as usual, I’d like to remind you that KMI’s earnings released today, and this call include forward-looking statements within the meaning 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 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 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 were 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.
Steven J. Kean — Chief Executive Officer
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 drew $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. 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 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 US.
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. 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 RINs 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 EPAs 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 conversation so far, there is significant interest in renewable natural gas in the so-called voluntary market. There are — 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 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, and 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, broader points about our business. The larger deal, Stagecoach, is the 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.
Kimberly Allen Dang — President
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, and that’s due to declines in Rockies production, and say a bill 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 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 ’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 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 ’20 and that 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 that we receive comes from fixed monthly charges we received for tanks under lease. But 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. But that still remains a little bit below 2019 of 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.
But 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 that’s in NGL prices, did offset some of the volume degradation. But if you compared our budget, we’re currently anticipating the 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. So 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 still experienced some weakness in our Jones Act tankers, and 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 gave you last quarter. The range we gave you last quarter was $5.1 billion to $5.3 billion. The outperformance versus the high-end of the 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.
David P. Michels — Vice President and Chief Financial Officer
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. So 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 loss — 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 EBDA and distributable cash flow performance, natural gas — 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 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 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. 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. And 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 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 that we provided in the first quarter. For debt to EBITDA, we expect to end the year at 4.0 times. And 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 that level — that 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.
Onto reconciliation of our net debt. The net debt for the quarter ended at $30 billion, 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, and we had $175 million worth of working capital source of cash flows, primarily interest expense accrual. And 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 spent $1.2 billion on dividends, we’ve spent $300 million in 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. And that explains the majority of the change for the year. That completes the financial review, and I will turn it back to Steve.
Steven J. Kean — Chief Executive Officer
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 up.
Questions and Answers:
Operator
Yes, sir. [Operator Instructions]. Please make sure that your phone is unmuted, and records your name and Company when prompted. [Operator Instructions]. Our first question comes from Jeremy Tonet from J.P. Morgan. Your line is open, sir.
Jeremy Tonet — J.P. Morgan — Analyst
Good afternoon.
Steven J. Kean — Chief Executive Officer
Good afternoon.
Jeremy Tonet — J.P. Morgan — Analyst
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?
Steven J. Kean — Chief Executive Officer
Sure, it is a very fragmented market as you pointed out, and that does create some, I think, some good open fields running for us. There aren’t as — 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.
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 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. And 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 do it in a way that the returns are attractive.
Jeremy Tonet — J.P. Morgan — Analyst
Got it. That’s helpful, thanks. And then 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, 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 I guess how you see Permian gas takeaway needs evolving over time?
Steven J. Kean — Chief Executive Officer
Yes, so agree generally with your projection there. 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, and 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 of 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.
Jeremy Tonet — J.P. Morgan — Analyst
Got it. I’ll leave it there. Thank you.
Operator
Thank you. Our next question comes from Shneur Gershuni from UBS. Your line is open, sir.
Shneur Gershuni — UBS — Analyst
Hi, good afternoon, everyone. Maybe I’ll start off on the guidance side. I definitely appreciate the color that you just provided to Jeremy’s question. But with respect to the guidance, it seems like it’s raised by a couple hundred million and sort of seemed to indicating about meeting or exceeding the top end of the range.
I was wondering if you can just sort of expand on the drivers on the change. Obviously, there’s the Stagecoach acquisition which 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?
Kimberly Allen Dang — President
Yeah. The two primary factors other than the Stagecoach acquisition are improved refined product volumes from what we’ve previously expected. And as we said, on the product side of the business, doal fuel is now flat with 2019 if you compare the second quarter of this year versus the second quarter of 2019.
And then the other primary driver is higher commodity prices. And I’m measuring — those are the primary changes against the high end of the guidance of $5.3 billion.
Shneur Gershuni — UBS — Analyst
Okay. Great. And maybe as a follow-up question. Last quarter when you adjusted your guidance, you sort of pulled forward the Ruby recontracting and sort — in fact I’ve sort of been thinking about the last three or four years, you’ve had like a recontracting trend in the Natural Gas segment. That’s essentially resulted in lower contract ranges and so forth. It’s been about $100 million to $200 million a year drag on EBITDA.
Is that now substantially over, and so all the growth-related projects that you’re talking about on the energy venture 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 done with the recontracting resets, maybe if there’s a little bit left, but is it substantially out of the way at this point?
Steven J. Kean — Chief Executive Officer
Yes. 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. But it is — we see it as being lower in terms of the roll off post 2021. And so 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.
And so, as we get to the end of those 10 or 10-plus-year contracts and they start to roll off, they’re rolling off into more challenged basis environment for those particular pipes. And so, that has had the effect of masking or dampening, however, you want to see it, some of the, I think, strong underlying performance in our Natural Gas Pipeline segment.
So 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, it is — 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, and those puts and takes and the uncertainty around them in further out periods are hard enough to quantify around, certain enough to quantify for me to give you a specific answer to your question about base business then plus. Right?
And so 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 make their own — come to their own expectations about that future, but we don’t guide beyond the current budget year or updates to the guidance like we’re giving you today.
So, we try to provide the transparency and particularly around the roll-off issue in particular, but we don’t guide beyond the current year.
Shneur Gershuni — UBS — Analyst
Just to clarify, so the roll-offs will continue for multiple years or are we approaching the end of it?
Steven J. Kean — Chief Executive Officer
There is still a couple of years to run, but they’re very modest after you get through this year. Quite modest.
Shneur Gershuni — UBS — Analyst
Okay. Got it. Okay. Perfect. Thank you very much. We really appreciate the color today.
Operator
Thank you. Next question comes from Spiro Dounis from Credit Suisse. Your line is open, sir.
Steven J. Kean — Chief Executive Officer
The overall on gas, the macro look on gas is we remain as others do, bullish on U.S. natural gas. And I think, we see, between now and 20 years from now, updated third-party analysis see growth in that market of about 23 DCF, or almost 24%, a pretty nice long runway. And a lot of that is driven by exports. There’s some industrial in there as well, but exports are a part of that picture. And 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. And the map of where those facilities are coming in is lined up very nicely with our natural gas pipeline footprint. And just to put a little more context on it, as we look at, and this is a different timeframe now, 2020 to 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.
It’s hard to predict the future, but I do think that given that demand growth seems pretty clear that we certainly going to have a tight market, at least for the intermediate term. What we’re seeing here 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, but I think there’s also a strong financial disappointment 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, and I hope for the next couple of years at least. And I think that means a higher price environment.
Spiro M. Dounis — Credit Suisse — Analyst
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 and not necessarily M&A, although I’m sure there remains an opportunity for you. And so as we’re thinking about the returns on organic growth, I think the press release cited a less than 6 times fully capitalized return on this project plus the M&A. And so I think a lot of us took that to mean that, organically, you can do even better than that. And so rereading through it the right way, are these 3 to 4X return type s of projects? At some point, do those get computed away? I’m just curious how you’re thinking about that component.
Steven J. Kean — Chief Executive Officer
Yeah. I don’t want to get into specific returns. There is — it is at least a potentially competitive environment out there. But the returns that we’re seeing are attractive for how we look at other deployments of capital in the expansion context. And we make appropriate adjustments 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. And if we got secured, firm, long-term fixed prices, we can look at that a bit differently. But they are good compensatory returns, and we are happy to invest in these opportunities.
Spiro M. Dounis — Credit Suisse — Analyst
Great. That’s all I had. Thanks, Steve.
Operator
Thank you. Next question comes from Keith Stanley with Wolfe Research. Your line is open.
Keith Stanley — Wolfe Research — Analyst
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? And then, I guess, bigger picture, can you talk a little more about the revenue streams for the business? You mentioned the RIN s. Can you benefit from the Low Carbon Fuel Standard, just other attributes in China, better understand the business? And then last parts of that is just, 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?
Steven J. Kean — Chief Executive Officer
I would ask Anthony to answer.
Anthony B. Ashley — Vice President of Energy Transition Ventures
On the last part of that, I think currently like now, about 60% is from the RNG side of the business, and the remaining piece from LNG. Once the redevelopment 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 that, obviously, the RNG component is increasing. And then sorry, remind me, Keith, on your — Yes. In order to capitalize on LCFS, you need to establish a pathway. We haven’t established a pathway, so these specific facilities, they are under contract locally with a transportations provider.
And MD&A internal rating the RIN s, you would have to settle that environmental attribute. Intech California established the pathway. And quite frankly, the California market has really dominated from an RNG standpoint, by really that [Indecipherable] side of the industry, because the carbon-intensity scores are much lower. And so there’s a much greater benefit for the RNG so LCFS a result of that. I would tend to think of it as terms of landfill is the market for it is really is outside of the California market.
Steven J. Kean — Chief Executive Officer
And then fixed price are variable today?
Anthony B. Ashley — Vice President of Energy Transition Ventures
Yes. There’s a certain part of the LNG offtake, which is take-or-pay currently. The RNG that’s going to be settled into the CNG market with the three development plans is effectively at an index price.
Keith Stanley — Wolfe Research — Analyst
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 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?
Steven J. Kean — Chief Executive Officer
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. If we did If — We did a bit of a sell-down on NGPL. We continue to operate it and continue to like our position in that asset. But we got good value there, and so we do look at those things. But I think we’ve done a good job, particularly in John Schlosser, the terminals business; pruning assets to stay focused on the things that we really do well over the years or our hub positions and the like. And so there’s not a have-to sell on anything, and we like the portfolio that we have today. But at the right price, we’ll transact.
Keith Stanley — Wolfe Research — Analyst
Thank you.
Operator
Our next question comes from Tristan Richardson from Truist Securities. Your line is open, sir.
Tristan Richardson — Truist Financial — Analyst
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 a precursor to that type of expansion that you had discussed back then, or can you remind us the potential size and scope of this project?
Steven J. Kean — Chief Executive Officer
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. And 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. And 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 unit — within the existing unit along the way. Jesse, anything you want to add? Okay.
Tristan Richardson — Truist Financial — Analyst
Thanks, Steve. And then 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?
Steven J. Kean — Chief Executive Officer
You 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. And then just overall, on 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.
Tristan Richardson — Truist Financial — Analyst
Thanks, Steve.
Operator
Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.
Jean Ann Salisbury — Sanford C. Bernstein & Co. — Analyst
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 just the timing of this potential opportunity, that 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?
Steven J. Kean — Chief Executive Officer
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 and get it into the pipe, etc. The other thing about it is the pipe itself. The CO2 moves most efficiently in a liquid state, which mean s high pressure.
That’s 1800 to 2200 PSI. And 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, and call it 600 psi or maybe 1,450 on the newer gas pipes. And so that has been 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. And so that does make that the near-term opportunity. So Having said that, I will ask Jesse to comment on the timing and current deal activities.
Jean Ann Salisbury — Sanford C. Bernstein & Co. — Analyst
Great. And can you comment on the system urgency any further?
Jesse Arenivas — President of CO2 & President, Energy Transition Ventures
There is a lot of interest. Obviously, the credits were clarified earlier in the year, so 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 in order and equipment, like I said, it’s probably a good year to 18 months away.
Jean Ann Salisbury — Sanford C. Bernstein & Co. — Analyst
Great. That’s all for me. Thank you.
Operator
Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Your line is open.
Michael Lapides — Goldman Sachs — Analyst
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 [Indecipherable] 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 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 the Elba fit into that? Because it seems like the infrastructure funds market, where others are paying pretty healthy multiples for minority stakes in LNG — 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?
Steven J. Kean — Chief Executive Officer
I’ll start with Elba and I’ll ask Conover to comment on Haynesville. You may recall — actually that’s, I think, predates you covering us. But we did sell down an interest in Venmo when we were post contract but still developing it. We did that. It was an attractive valuation for us and it helps share the capital burden. And so we’ve done that move, if you will, already. And in terms of it’s — 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, and it’s interconnected with our SNG system. And so, it fits nicely within the portfolio of assets we have. Also, as you know, it’s under a long-term contract with Shell, which is an attractive credit and risk profile for us, a very long-term contract with Shell. It fits very well and we did a partial sell-down earlier, as I mentioned. Tom, on the Haynesville takeaway needs.
Tom Martin — President, Natural Gas Pipelines
I think given the increase in gas prices and the activity that we’re seeing in the Haynesville sector, 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 and they are, I think, living within their means managing their balance sheet s appropriately. I don’t think the activity is definitely increasing. But I think if we see sustained gas prices and additional activity in the [Indecipherable] There will be 3-5 years, probably closer to a 3-year timeframe. There may be a need for additional capacity out of that market.
Michael Lapides — Goldman Sachs — Analyst
Got it. Thank you, guys. Much appreciated.
Operator
Thank you. Our next question comes from Becca Followill with U.S. Capital Advisors. Your line is open.
Becca Followill — U.S. Capital Advisors — Analyst
Hi, guys. Two questions, one minor. But 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?
Steven J. Kean — Chief Executive Officer
Visiting the non-recurring items, Becca.
Becca Followill — U.S. Capital Advisors — Analyst
Right. And if you want, I can ask another question while you’re looking that up.
Steven J. Kean — Chief Executive Officer
It’s okay. Go ahead.
Becca Followill — U.S. Capital Advisors — Analyst
Okay. I could already tell, then you’ll shoot. The other side — it’s a variation on what Tristan asked, is to see to we’ve got oil prices now close to $70, which is — probably it’s 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 had backed off on spending?
Steven J. Kean — Chief Executive Officer
Yeah, so we will continue to look at that like we always have, Becca, which is, we looked 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.
And so we’ll continue to look for those. And we’ve also seen — it’s true, we are experiencing year-over-year declines in that production. But we’re 5% above our plan. And that is some better performance from some of our SACROC developments, as well as a lesser decline rate than what we expected on some previous developments. And so, doing well versus our plan and continuing to invest opportunistically as we always have.
Becca Followill — U.S. Capital Advisors — Analyst
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?
Kimberly Allen Dang — President
$70 and 3.50. So $70 on crude and &3.50 on gas for the back half of the year.
Tom Martin — President, Natural Gas Pipelines
For the balance of the year.
Becca Followill — U.S. Capital Advisors — Analyst
Got you. Thank you.
David P. Michels — Vice President and Chief Financial Officer
Okay. And 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 had — that we have outstanding. We’re getting a little closer to settlements so we took a reserve there.
And we also took some 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 with, now that we have more information. And these things are hard to call and come up sporadically, so I don’t think that this is something that we’d anticipate recurring on a regular basis, but they come up sporadically.
Becca Followill — U.S. Capital Advisors — Analyst
All right. Thank you.
Operator
Thank you. Our next question comes from Christine Cho with Barclays. Your line is open.
David P. Michels — Vice President and Chief Financial Officer
Yeah. 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. But if we plan to fund our share of it, it’ll be part of the use of cash that we would expect for next year.
Steven J. Kean — Chief Executive Officer
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.
Christine Cho — Barclays — Analyst
Do you have a timeframe on when exactly?
Steven J. Kean — Chief Executive Officer
We’re not the only person at the table, so we can’t say that.
Christine Cho — Barclays — Analyst
Okay. Thanks.
Operator
Thank you. Our next question comes from Pearce Hammond with Piper Sandler. Your line is open.
Pearce Hammond — Piper Sandler — Analyst
Good afternoon and thanks for taking my questions. You have a great slide in your deck Slide 24 that details the current estimate to U.S. carbon capture cost with ethanol in 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?
Steven J. Kean — Chief Executive Officer
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, carbon capture just generally. And so I think there is interest in doing that and expand ing 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. Now, predicting where that will come out, I will not even venture a guess.
Pearce Hammond — Piper Sandler — Analyst
And then, Steve, thank you for that. And as a follow-up, I know natural gas power plants, combined cycle power plants are listed on the high end of the cost — carbon capture costs in your graphic. But 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?
Steven J. Kean — Chief Executive Officer
Very preliminary conversations with one of our power customers, but I would just say very preliminary, very preliminary.
Pearce Hammond — Piper Sandler — Analyst
But definitely more interest on the — from the ethanol side?
Steven J. Kean — Chief Executive Officer
That’s just more within reach on the ethanol and the gas processing side, for the reasons that you pointed out.
Pearce Hammond — Piper Sandler — Analyst
Great. Thank you very much.
Operator
Thank you. Next question comes from Michael Blum with Wells Fargo. Your line is open.
Michael Blum — Wells Fargo — Analyst
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, just how you’re thinking about where buybacks fit into the mix in terms of capital allocation? And clearly, this quarter it seems like you prioritized acquisition, so just want to get your thoughts on all that.
Richard D. Kinder — Executive Chairman
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 they’re very strategic to us. We intend to continue to pay a good dividend or raising the dividend. And then we’ll look opportunistically at the opportunity to repurchase shares. And we’re looking at all those in concert. And so it just depends on what the opportunities are.
Michael Blum — Wells Fargo — Analyst
Okay. Got it. And then I guess my other question is on Stagecoach. So 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 looks like roughly so that as rates do go higher, you’ll able to capture that? Thanks.
Steven J. Kean — Chief Executive Officer
Yeah. So 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. And so that’s the general contractual timeframe. But 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’ve done on a standalone basis. And the rates within — the rates for Stagecoach services are market-based rates as well.
Michael Blum — Wells Fargo — Analyst
Perfect. Thank you so much.
Operator
Thank you. Next question comes from Jeremy Tonet with JPMorgan. Your line is open.
Jeremy Tonet — J.P. Morgan — Analyst
All right, thanks for let ting me speak one more, and just wanted to touch on carbon sequestration real quick. If 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 6 wells such as what happened with Wyoming and North Dakota? And do you think that the wells — there’s a greater chance that’s offshore, onshore, just given offshore being more costly, but having benefits such as the rights for space, ports, what have you. I was just wondering your thoughts on sequestration development.
Steven J. Kean — Chief Executive Officer
It will shorten up the timeframe if the Texas Railroad Commission is in-charge of it. And now there’s a process 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. But then they have to go put their plan together and put that on file, which could be this fall. And then I don’t know how long it will take the EPA necessarily to act. But once it acts, and the Railroad Commission has control of it, I think they’re going to process it 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? But it’s five or six years right now. That doesn’t work, and so 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, 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 the existing pipeline network is, which is a very important consideration for the reasons I’ve said earlier. But, Jesse, do you have any other comments on onshore versus offshore?
Jesse Arenivas — President of CO2 & President, Energy Transition Ventures
Yeah, I agree the surface ownership rights is important, but we — there are opportunities onshore as well, where you have common ownership. Looking at both, but more cost effective to do onshore at this point.
Steven J. Kean — Chief Executive Officer
The common ownership between the surface…
Jesse Arenivas — President of CO2 & President, Energy Transition Ventures
Surface and the middle. Yeah.
Jeremy Tonet — J.P. Morgan — Analyst
Got it. Thank you.
Operator
Thank you. Our next question comes from Colton Bean with Tudor, Pickering, Holt & Company. Your line is open.
Colton Bean — Tudor, Pickering, Holt & Co. — Analyst
Thanks. Just one on my end. A lot of questions on RNG and CPS. 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?
Jesse Arenivas — President of CO2 & President, Energy Transition Ventures
Yeah. There’s certainly an opportunity. It’s going to be a scale issue. These RNG facilities are relatively small at the plants themselves, so depending on the growth and the size of the emission, it will be challenging. But there is an opportunity.
Colton Bean — Tudor, Pickering, Holt & Co. — Analyst
Thank you.
Operator
Thank you. There are no further questions in queue at this time.
Richard D. Kinder — Executive Chairman
We thank all of you for listening to us and have a good evening.
Operator
[Operator Closing Remarks]