Good afternoon, ladies and gentlemen, and thank you for standing by. Welcome to the Energy Transfer Third Quarter Earnings Call. [Operator Instructions] Please note, this conference is being recorded. I will now turn the conference over to your host, Tom Long, Co-Chief Executive Officer for Energy Transfer. Thank you. You may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Third Quarter 2021 Earnings Call, and thank you for joining us today. I'm also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based on our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our quarterly report on Form 10-Q for the quarter ended September 30, 2021, which we expect to be filed tomorrow, November 4. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, all of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. I'd like to start today by looking at some of our third quarter highlights. We generated adjusted EBITDA of $2.6 billion and DCF attributable to the partners of Energy Transfer, as adjusted, of $1.3 billion. Our excess cash flow after distributions was approximately $900 million. On an incurred basis, we had excess DCF of approximately $540 million after distributions of $414 million and growth capital of approximately $360 million. Operationally, our NGL transportation and fractionation and NGL refined products terminals volumes reached new records during the quarter, largely driven by growth in volumes, beating our Mont Belvieu fractionators and Nederland Terminal. As the market continues to recover, we are well positioned to benefit from increasing demand and higher margins. Switching gears to an update on the acquisition of Enable Midstream Partners, which will provide increased scale in the Mid-Continent and Ark-La-Tex regions and improved connectivity for our natural gas and NGL transportation customers. We expect the combination of Energy Transfer’s and Enable’s complementary assets to allow us to provide flexible and competitive service to our customers as we pursue additional commercial opportunities utilizing our improved connectivity and increased footprint. As a reminder, we expect the combined company to generate more than $100 million of annual run rate cost synergies, and this is before potential commercial synergies. We continue to believe that the transaction will close before the end of the year. I'll now walk you through recent developments on our growth projects, starting with our Cushing South pipeline. In early June, we commenced service to provide transportation for approximately 65,000 barrels per day of crude oil from our Cushing terminal to our Nederland terminal, providing access for Powder River and DJ Basin barrels to our Nederland terminal being an upstream connection with our White Cliffs pipeline. This pipe is already being fully utilized. And as we mentioned on our last call, we are moving forward with Phase 2, which will increase the capacity to 120,000 barrels per day. Phase 2 is expected to be in service early in the second quarter of 2022 and is underpinned by third-party commitments. As a reminder, minimal capital spend is required for this phase. Next, construction on the Ted Collins link is progressing and is now expected to be in service late in the first quarter of 2022. The Ted Collins link will give us the ability to fully load and export unblended low-gravity Bakken and WTI barrels out of the Houston market, showcasing Energy Transfer's unique ability to provide a net Bakken barrel to markets along the Gulf Coast. Now turning to our Mariner East system. We have commissioned the next significant phase of the Mariner East project, which brings our current capacity on the Mariner East pipeline system to approximately 260,000 barrels per day. Year-to-date, NGL volumes through the Mariner East pipeline system and Marcus Hook Terminal are up 12% over the same period in 2020. We are awaiting the issuance of a permit modification for the conversion of the final directional drill to an open cut, which will allow us to place the final segment of Mariner East into service in the first quarter of 2022. Our Pennsylvania Access project, which will allow refined products to flow from the Midwest supply regions into Pennsylvania, New York and other markets in the Northeast, will begin moving refined products this winter. Now for a brief update on our Nederland terminal. As a reminder, with the completion of the remaining expansions of our LPG facilities at Nederland, earlier this year, we are now capable of exporting more than 700,000 barrels per day of NGLs from our Nederland terminal. And when combined with our export capabilities from our Marcus Hook Terminal as well as our Mariner West pipeline, which exports ethane to Canada, our total NGL export capacity is over 1.1 million barrels per day, which is among the largest in the world. At our expanded Nederland terminal, NGL volumes continued to increase during the third quarter, including export volumes under our Orbit ethane export joint venture, which has remained strong. Year-to-date through September, we have loaded more than 16 million barrels of ethane out of this facility. And in total, our percentage of worldwide NGL exports has doubled over the last 18 months to nearly 20%, which was more than any other company or country for the third quarter of 2021. Looking ahead, we expect our total NGL export volumes from Nederland to continue to increase throughout next year. In addition, demand for supply to refineries remain strong, and our crude oil storage at Nederland is fully contracted. At Mont Belvieu, we recently brought on a 3 million-barrel high-rate storage well, which takes our NGL storage capabilities at Mont Belvieu to 53 million barrels. And our Permian Bridge project, which connects our gathering and processing assets in the Delaware Basin with our G&P assets in the Midland Basin was placed into service in October and is already being significantly utilized. This project allows us to move approximately 115,000 Mcf per day of rich gas out of the Midland Basin and to operate existing capacity more efficiently while also providing access to additional takeaway options. In addition, it can easily be expanded to 200,000 Mcf per day when needed. Lastly, in July, we announced the signing of a memorandum of understanding with the Republic of Panama to study the feasibility of jointly developing a proposed Trans-Panama Gateway Pipeline. We believe this project would create the most liquid and attractive LPG supply hub in the world and are excited about the opportunity it presents. Now for an update on our alternative energy activities, where we have continued to make progress on a number of fronts. In September, we entered into a 15-year power purchase agreement with SB Energy for 120 megawatts of solar power from its Eiffel solar project in Northeast Texas. This is the second solar project we are participating in and these agreements provide a good fixed price per megawatt hour on a generated basis. So we only pay for power actually generated and delivered to us. We're also continuing to explore several opportunities for solar, wind and forestry carbon credit projects on our existing acreage in the Appalachian region. In particular, we're continuing to jointly pursue solar and wind development on the Energy Transfer track in Kentucky with a large utility company, and we are in discussions with other large renewable energy developers. On the carbon capture front, our Marcus Hook project looks financially attractive based upon preliminary cost estimates and design feasibility studies. This project would involve capturing CO2 from the flue gas and delivering it to customers for industrial applications and is used in food and beverage industries. We're also pursuing several carbon projects related to our assets, including projects involving the capture of CO2 from processing plants for use in enhanced oil recovery or sequestration. We continue to believe that our franchise will allow us to participate in a variety of projects involving carbon capture or other innovative uses as we continue to reduce our carbon footprint. Lastly, we expect to publish our annual corporate responsibility report for our website shortly. Now let's take a closer look at our third quarter results. Consolidated adjusted EBITDA was $2.6 billion compared to $2.9 billion for the third quarter of 2020. DCF attributable to the partners as adjusted was $1.31 billion for the third quarter compared to $1.69 billion for the third quarter of 2020. While we saw higher volumes across the majority of our segments, including record volumes in the NGL and refined products segment, these benefits do not offset the significant optimization gains in the third quarter of 2020 related to our various optimization groups as well as the onetime $103 million gain in our Midstream segment. In addition, the third quarter of 2021 included higher utilities and other Winter Storm Uri related expenses. On October 26, we announced a quarterly cash distribution of $0.1525 per common unit or $0.61 on an annualized basis. This distribution will be paid on November 19 to unitholders of record as of the close of business on November 5. Turning to our results by segment, and we'll start with the NGL and refined products. Adjusted EBITDA was $706 million compared to $762 million for the same period last year. Higher terminal services and transportation margins related to the increased throughput on our Nederland and Mariner East pipelines in the third quarter of 2021 were offset by a $55 million decrease in our optimization businesses at Mont Belvieu and in the Northeast as well as increased OpEx and G&A. NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record 1.8 million barrels per day compared to 1.5 million barrels per day for the same period last year. This increase was primarily due to increased export volumes feeding into our Nederland terminal from the initiation of service on our propane and ethane export projects, higher volumes from the Eagle Ford region as well as increased volumes on our Mariner East and Mariner West pipeline systems. And our fractionators also reached a new record for the quarter with an average fractionated volumes of 884,000 barrels per day compared to 877,000 barrels per day for the third quarter of 2020. Throughout 2021, we have continued to add volumes to our system and are well positioned to capture additional volumes and capitalize on new opportunities as demand improves. For our crude oil segment, adjusted EBITDA was $496 million compared to $631 million for the same period last year. The improved performance on our Bakken and Bayou Bridge pipelines as a result of recovering volumes in the third quarter of 2021 did not offset approximately $100 million of onetime items in the third quarter of 2020. In addition, we had approximately $20 million in other optimization reductions as well as increased OpEx and G&A expense year-over-year. For midstream, adjusted EBITDA was $556 million compared to $530 million for the third quarter of 2020. This was largely the result of a $156 million increase related to favorable NGL and natural gas prices as well as volume growth in the Permian and the ramp-up of recently completed assets in the Northeast, which were partially offset by a decrease of $103 million due to the restructuring and assignment of certain contracts in the Ark-La-Tex region in the third quarter of 2020. Gathered gas volumes were 13 million MMBtus per day compared to 12.9 million MMBtus per day for the same period last year due to higher volumes in the Permian, Ark-La-Tex and South Texas regions. Permian Basin volumes continue to be strong and Midland Inlet volumes remained at or near record highs. As a result, we are already utilizing our Permian Bridge project to enhance the efficiency of our processing in the area by moving some volumes over to our Delaware Basin processing plants. In our Interstate segment, adjusted EBITDA was $334 million compared to $425 million for the third quarter of 2020 primarily due to contract expirations at the end of 2020 on Tiger and FEP as well as a shipper bankruptcy on Tiger and lower demand on Panhandle and Trunkline partially offset by an increase in transported volumes on Rover due to more favorable market conditions. And for our intrastate segment, adjusted EBITDA was $172 million compared to $203 million in the third quarter of last year. This was primarily due to lower optimization volumes as a result of third-party customers shifting to long-term contracts from the Permian to the Gulf Coast and lower spreads as well as an increase in operating expenses, which were largely offset by increased transportation volumes out of the Permian and an increase in retained fuel revenues and storage margin. While it impacted us over the comparison period, the additional long-term contracting of third-party customers from the Permian to the Gulf Coast is expected to benefit us going forward as the Waha to Katy basis differential has tightened significantly. To reduce volatility within our earnings and protect us from falling basis differentials like we saw from the third quarter of 2020 to the third quarter of 2021, we have strategically taken steps to lock in additional volumes under fee-based long-term contracts, which are exceeding current differentials. Now turning to our 2021 adjusted EBITDA guidance. Our full year 2021 adjusted EBITDA remains $12.9 billion to $13.3 billion. As a reminder, this range excludes any contributions from the announced Enable acquisition. And moving to a growth capital update, for the 9 months ended September 30, 2021, Energy Transfer spent $1.08 billion on organic growth projects, primarily in the NGL refined products segment, excluding SUN and USA compression CapEx. For full year 2021, we continue to expect growth capital expenditures to be approximately $1.6 billion, primarily in the NGL refined product, midstream and crude oil segment. After 2022 and 2023, we continue to expect to spend approximately $500 million to $700 million per year. Now looking briefly at our liquidity position. As of September 30, 2021, total available liquidity under our revolving credit facilities was approximately $5.4 billion, and our leverage ratio was 3.15x for the credit facility. During the third quarter, we utilized cash from operations to reduce our outstanding debt by approximately $800 million. And year-to-date, we have reduced our long-term debt by approximately $6 billion. We have done a lot of heavy lifting over the last few years as we work to accelerate our debt reduction, improve our leverage and best position ourselves to return value to our unitholders. We expect to generate a significant amount of cash flow in 2022, and paying down debt continues to be our top priority. Additionally, our strong performance in 2021 opens the door for the potential to begin returning value to our unitholders in the form of distribution increases and/or buybacks beginning next year. During the third quarter, we continue to see volumes recover across several of our systems as well as improve fundamentals. In addition, our Nederland and Mariner East expansion projects drove record volumes in our NGL and refined products segment, and we expect total NGL exports to grow throughout 2022. Overall, our assets continued to generate strong cash flow, which allowed us to internally fund our growth projects and further reduce debt in the third quarter. We remain committed to maintaining and improving our investment grade rating and continue to place a significant amount of emphasis on capital discipline, deleveraging and maintaining financial flexibility. We continue to be excited about the acquisition of Enable, and we believe we will be able to use our enhanced footprint to improve efficiencies and pursue new commercial opportunities. How we participate in the evolving energy world is a key focus, and we continue to make progress on a number of our alternative energy projects, which we can enhance and effectively grow our energy franchise with preliminary cost estimates looking favorable. Operator, please open the line up for our first question.

[Operator Instructions] Our first question is from Shneur Gershuni with UBS.

Tom, maybe we can start off with the quarterly results and how we should think about them with respect to the unchanged guidance. We saw some higher volumes but we also saw some lower margins. For example, in the NGL transportation segment, costs are up, but you had sort of intimated that costs were going to be up earlier this year. Just wondering if this quarter's results was kind of how you thought it was going to play out as guidance was originally constructed and whether we should be thinking that towards the midpoint or towards the lower end. Is there some seasonality that we should be thinking about with all the contract restructuring that's occurring? I'm just wondering if you can sort of give us some color about the shape and how we should be thinking about this specific quarter, just given some of the margin compression that we've seen.

Yes. Good afternoon, Shneur. As we obviously started the year, we had the initial guidance we gave and then we had, obviously, a very, very strong first quarter. So as we look out over the year, I think it’s the first part of your question there about what we were expecting, this is pretty much in line. I will say that it was probably a little bit higher optimization activities that we were anticipating in some of the segments, NGL and refined products. Crude oil would probably be another one. So this is really playing out maybe a little bit softer than what we were anticipating, but we still feel good about the guidance that we provided. And I think the last part of your question as to where we would anticipate coming in. I think in fairness, it’d probably be coming in at the lower end of that range. Is probably where we see it right now. But once again, we have a lot of good positive volumes moving through, and with the continued optimization opportunities, we do feel very, very good about the year.

Great. And maybe as a follow-up question, on Slide 6, you maintained the $500 million to $700 million a year in growth capital for both 2022 and 2023, and that seems to be unchanged. You’ve made progress paying down debt during the quarter and so forth. You talked about return of capital along the lines of distribution increases, buybacks and so forth. Is there a new leverage target that we need to be thinking about? Is it still to get below 4.5 before we can some sort of a pivot? Just kind of wondering what your latest thoughts are on that side.

We would -- our target is still that 4 to 4.5 range. But Shneur, like I stated in the past, we do always look out at the forecast. So when we make these decisions, we're not just looking at any one specific point in time. We're looking at our projections and where we see the leverage going. So it's something that's more of an outlook. So there's not a bright line, if you will. So that's the reason we felt comfortable saying that we look at returning some to our -- returning capital to our unitholders even in the form of distributions or unit CapEx. Yes, I said beginning next year. I want to be sure I add that into the answer.

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

I guess first question around kind of the ethane markets. And specifically, we've got -- for ethane demand, we've got about 280,000 barrels a day of cracker capacity that's set to come online over the next 1.5 years or so. So that's going to be a sizable pull on ethane volumes here in the U.S. So I guess maybe if you could kind of talk to how you think -- or kind of where those volumes, those ethane volumes come from, do you think it's kind of more underlying NGL growth? Or do you think it's more so less ethane rejection? Or do you think there's any risk that you actually export less ethane volumes as these crackers come online?

Chase, this is Mackie. Yes, I’ll tell you what a great question. We love these types of questions because Energy Transfer has positioned itself to really be the leader in not only ethane but all NGLs. As you know, we were the first export of ethane into Canada, and then we’ve grown our export business ethane in Marcus Hook and out of Nederland. We also are unique in that we control the vast majority of the ethane that we receive at the tailgate of our frac. So unlike some of our peers, we actually control an enormous amount of ethane that, indeed, the world is searching for. And we have -- with RB and his team, we have continuous conversations with companies all over the world. South America, Asia, Europe, China. We expect that business to grow. As you know, we brought on a satellite this year, and they’ll be bringing their second frac on next year. So we’ll be ramping those volumes up. We already have approval for a 70,000 and 140,000 barrel a day expansion at Marcus Hook, and we’re just looking and negotiating with customers to get to FID on those projects. So ethane and propane have such bright futures, and we are very pleased to be situated where we are to participate in those markets.

Okay. Perfect. Unrelated follow-up, but I kind of have to ask on Biden’s kind of build back better plan. How do you think this is going to influence ET’s strategy over the medium to longer term?

Gosh, this is Mackie. I’ll start. I want to follow up. I had to answer that. We don’t really -- whatever comes out of those plans and out of all that legislation, we’ll deal with that when that comes out and once it gets budgeted on. But we’re keeping our heads down. We’re in the fossil fuel business. We play an integral part in producing, transporting, fracking and exporting and also selling to the domestic markets the enormous amounts of energy that make the living standards as we have them here and around the world. And we are excited about our industry. We see a long future in this industry. We see a significantly growing demand for natural gas and especially for propane and ethane, for ethylene and propylene and other very critical products that are -- play such a big role in everyday life. So we don’t really -- we try -- of course, we pay attention to politics. Of course, we pay attention to any tax impacts it may have on our partnership but we don’t really get all worried and caught up in that. We’ll deal with it when it comes out. But in the meantime, we’re just trying to generate revenues for our unitholders.

Our next question is from Jean Salisbury with Bernstein.

Could you kind of talk about why mainly optimization has lagged your estimates? And is there like a minimum that optimization could be? And are we near that here?

This is Mackie again. Yes, as Tom was referring to, optimization opportunities, especially material ones like we saw in 2020, you can't predict those. You can't predict a pandemic. You can't predict oil going to a negative zero and you can't predict it bouncing back up in a relatively small period of time to the mid-40s or $50 a barrel. So the fortunate thing about our assets, both our crude assets, our NGL assets and our natural gas assets is we have a tremendous amount of storage. So it does give us the ability to put products into storage and hedge them out, say, for example, this winter. And then if we have any type of winter events or any type of pricing volatility events, we are able to really benefit from pulling our products out at much higher margins than we expected. So it's hard to predict. We certainly position ourselves to take advantage of any of that volatility in the market. like we saw this past February, but we certainly don't project that into our budget or into our outlook in the coming years.

Okay. I mean, is it fair to say, I guess, that since there has been kind of less volatility in the market than you had kind of projected at the beginning of the year?

Yes. Yes, we don’t -- I’m sorry, I didn’t totally follow the question, but we were well situated to benefit not only our revenues but also the customers and the people of Texas and Uri. But -- as I mentioned, we’re also set up this year. If there’s any types of cold falls or any type of significant volatility in pricing. We’re well positioned to be able to provide what will be necessary for customers in this state and throughout the country.

Okay. That makes sense. And then -- and you mentioned that the next satellite cracker comes on next -- sometime next year. Do you have a sense of when in the year that will start? And do you get -- do you start getting paid basically when those shipments start?

Yes, the second question, I believe the latest we heard was the third quarter of next year. I can’t say that with absolute certainty. That’s the last thing we heard. I meant to check on that before this call, and I have not heard an update. So I believe that’s it.

Our next question is from Keith Stanley with Wolfe Research.

One small one, just a follow-up on the quarter. So you’ve talked to, I guess, the optimization headwinds. There’s also a driver side of unfavorable crude inventory valuation adjustments. Was that a big driver for the crude segment? And I guess also was the Bakken pipeline expansion fully in the crude segment results for Q3?

Let's start with the inventory gains. This quarter, you saw about $33 million. And some of that is because of the absolute lower inventory balance that we're keeping also versus $67 million in the quarter, the quarter last year, both those being gains, but you can see that's where the -- that's really kind of where the spread is there. I think as far as the second part of it, yes. The Bakken pipeline was in there.

Okay.

And I might add in there still ramping up. Is that -- was that your question, Keith, just to make sure on that, were you talking about the expansion?

Yes. That’s right. Okay. So that’s still ramping into Q4, I guess.

Yes. I'll give a little clarity. This is Mackie. We brought that on in August. And when we brought that project on the optimization to increase the capacity, the demand charges kicked in on that. So the volumes will be what the volumes will be, and the drilling needs to pick up in the Bakken to really see those volumes grow. But the bottom line is we are receiving demand charges for the incremental capacity we've created for a significant portion of it.

Got it. Separate question just on capital allocation. So Tom, you said debt repayment is still a priority for the company. I guess you have about $1 billion plus of maturities coming up in the first quarter. Should we assume that's kind of consistent with what you've been doing in 2021 that you would repay that with your free cash flow as well? And then on the distribution, I'm just curious when you talk about looking at distribution increases next year, is it -- do you view it -- I mean you cut the distribution last year to basically put cash to the balance sheet not because you couldn't pay it. So how would you look at it when you get into next year? Is the goal to kind of get back to where you were? Do you factor in where the yield is? Just trying to get a sense of how you would look at the distribution once you're comfortable with where the balance sheet is.

All right. Keith, let's start off with the first part of your question on the debt. You probably saw we had $1.9 billion already. And on November 1, we have $1 billion of that. And on December 1, we'll pay off the other $900 million. So we're going to continue as these maturities -- as these maturities come forward, we will continue to pay them down. If some opportunity comes along that maybe you want to term some out, I'm not going to take that completely off the table. But right now, we are continuing to pay down these maturities and even call some early as they come up. I think the second part of your question, that's -- those are discussions that we continue to have with the Board. I wouldn't say that there's any more definitive I can tell you at this time other than both the buybacks and the distributions are very much front and center as we look at them. But I want to make sure the first part of your statement that maintaining financial flexibility is definitely a top priority.

Our next question is from Jeremy Tonet with JPMorgan.

Just wanted to start off, I guess, at a higher level, if you could provide any color as far as what you're seeing on producer activity. Especially as you're heading into '22 year ahead, we've seen kind of bifurcation with the private getting after and the public being more disciplined. Do you expect those trends to continue? Or do you see anything changing there? And how much does this value across base?

Jeremy, this is Mackie. You said it well, and that’s kind of what we saw this year. It’s what we are seeing going in next year. The majors are just much more cautious. They’re watching capital much more closer than a lot of the independents. So at least around a lot of our assets, we are seeing more activity and more production coming on with the smaller companies, the smaller independents. However, some of these majors, especially out in the Permian Basin in the Northern Louisiana area and even in the Marcellus Utica, we are seeing rigs come back in, as everybody knows. I think rigs in North Louisiana are up about 45% from where they were a year ago -- a little over a year ago, and we’re seeing a similar type growth out in the Permian. There’s still a lot of DUCs out in the Permian that have not been completed. A number of them have been but we are seeing a lot of those now being completed as we go into 2022. So I think we would describe it, at least around our system, is just consistent growth not just a hard ramp in the first or second quarter but just consistent growth throughout the year, both in rigs and in volume growth out in the Permian. We do expect faster growth on the more leaner gas in Northern Louisiana. And we see kind of similar gradual growth in the Eagle Ford down South Texas on our assets down there.

And just want to pick up on some of your comments before. And certainly, hydrocarbons are important to improving the standard of global living here. But looking at Slide 7, you talk about the alternative energy group here. And I just want to see which specific opportunities are you guys kind of focused on right now? Do you see opportunities in black carbon or using right of ways for electric transmission? And I know everything coming out of D.C. is clear as mud. But if we get things like higher 45 Qs or renewables, including qualified income, what could this mean for you guys?

Yes. Tom Mason in his group, of course, are today following that and we're looking for what comes out of Congress with the 45Q and other tax benefits around renewables. As we've said before, our focus is really on the missions to our assets, in other words around our processing plants, our treating facilities. We're looking to capture carbon, whether we do it, partner up with somebody or allow somebody else to capture that. We are also looking at some -- catching some carbon off some of our facilities up in the Northeast. We have our Marcus Hook facility. We're looking to capture some gas. We've done some preliminary studies. They actually look very promising at some rates of return that makes sense, and so we will continue to pursue those. And we're also looking at some carbon capture down in South Texas that will either be sequestered or part of an ERR project. So we are proceeding. We're doing that on a daily basis. Tom and his team are looking at deals all across the board, whether it's black carbon or whether it's taking natural gas and converting it to a gasoline or whether it's renewable diesel and transporting that through our diesel pipeline system, we're looking at all of that, and we'll continue to participate in that as we have around the solar business, where we are not invested in that from a capital perspective but we're certainly investing in our commitment to purchase what we see as very inexpensive power. So we are supporting renewables in that way or that manner. But we'll continue to pursue those that make sense, and we do expect to consummate some of those in the distant future not necessarily a tremendous amount of capital, but we do see several projects that may involve up to $20 million or $30 million of capital around CO2 sequestration. So that is going to remain a focus of ours as we go into '22 and beyond.

Our next question is from Colton Bean with Tudor, Pickering, Holt.

So maybe just circling back to the comments on the interstate segment. It looks like the transportation margin on a per unit basis fell quite a bit relative to the first half of the year. So I just wanted to clarify, it sounded like that was primarily attributable to shorter term. I’m sorry.

Intrastate?

Intra, the Texas, Texas pipes. Yes. It looks like the transportation margin on a per unit basis fell a decent bit relative to what we saw in first half. And I think, Tom, you might have spoken to this, but just wanted to clarify. It sounded like that was primarily attributable to higher rate short-term contracts that maybe Whistler changed the dynamic there. Just wanted to understand what was kind of going on between first half of the year and Q3?

You bet. This is Mackie again. So prior to the last 3, 42 inches that have come on in the last couple of years, -- we -- that was kind of our bread and butter. It’s moving gas across the state. We saw spreads of $1.50, $2. And those, of course, started to come in. So we started a strategy about a couple of years ago to look to secure longer-term commitment at not $1, $1.50 spreads but a good healthy spread, and that’s what we began doing. So when you look at the third quarter, the spreads were up as much as $0.75 or $0.80 on average for that quarter. We did secure during prior -- I mean, I’m sorry, last year that impacted third quarter of this year at lower than that $0.75 or $0.80 but much higher than where the spreads are today. It’s a strategy that made sense to us to. Where we could see the spreads coming in at least in the short term, we think this will be short-lived. In 2 to 3 years, we believe the basis will blow back out. There will be more need. Look at the growth in the Permian Basin and natural gas is just incredible. But in the meantime, we did want to secure some of our capacity at healthy margins for longer-term contracts.

Got it. And with this kind of even the last of the greenfields to your point, is this a safe run rate look at ahead of just kind of looking at where the basis goes from here?

Yes. I'll answer it like this, that we've seen spreads fall to $0.25 -- $0.20, $0.25, $0.30 here as of recent. We do believe, and I believe the industry believes that over the next 1.5 years to 2 years that, that will start moving back out. We may see $0.75 or $1. We have some of our competitors out there talking about building in maybe another 42-inch. What we're trying to tell the marketplace and the producers and shippers before they commit another project, we'll have capacity. We have capacity coming available in 2 or 3 years from now. And we'd love to lock it in for prices similar to what they would pay on new build on greenfield projects. So we are very well positioned to kind of weather the storm here as all the -- these 42 inches have been completed as the gas begins to grow and fill them up. And once they all become full, we're very well positioned to capture bigger spreads on capacity we'll have on our gas system.

Got it. And maybe just a little bit more of a niche topic here. The legacy PBR assets, do you all still have any exposure there in terms of what we’re seeing on price hikes in the coal market right now? Or alternatively, is this a more attractive seller’s market where you might look to divest some of those legacy assets?

No, I wouldn’t say that there would be any opportunity for spike there. As you know, that’s a very small -- very, very small piece that sits up there. It’s a royalty business. So I wouldn’t guide you toward anything there. As far as divestiture, there’s no plans, no dialogue going on, on that front.

Our next question is from Michael Blum with Wells Fargo.

I wanted to ask about Rover. You highlighted a $13 million increase in revenue. Just wanted to hear what the dynamics are on Rover right now. How much of that is contracted? And I guess given that the basin is pretty tight on takeaway, is there an ability to sign up more producers at higher rates?

Yes. Michael, this is Mackie. What a great project. That’s really turned out well for us. We saw -- for example, we saw a hiccup on Petco’s pipeline here a couple of months ago, and we saw the value of that pipeline increase even more so with the difficulty that we see in the -- at least the near term, over the next 2, 3, 4, 5 years, how difficult it will be to get another interstate pipeline approved out of that area. So we’re so well positioned. We do have probably approximately over 90% of it under long-term contracts on a month-to-month basis. Many times, we’re selling capacity at tariff rates depending on the month, depending on whether they’re going to down or going south to Zone 1a. So it’s such an excellently strategically located asset. As we see volumes grow at the Marcellus Utica, it’s kind of unique in the sense that it can move barrels up to the north into Canada. And as you know, it can move barrels all the way down to Gulf Coast to provide supplies for LNG facilities as well other markets on the Gulf Coast. So we’re -- we consistently move about 3.2 to 3.4. We can move as much as 3.55, I believe it is. And so we’ll continue to see that kind of grow both in filling up to the max and also at max tariff rates as the future -- as we go into the future.

Got it. And then just a quick follow-up for me. So your CapEx for ‘22 and ‘23 of that $500 million to $700 million per year range, I’m assuming that does not include any potential spending on these initiatives you have going on in Panama. So I guess the question is if this MOU becomes an FID project in Panama, how does that change those numbers?

It would certainly add to those numbers, but getting that project to FID, it's down the road. We're probably talking at least 12 months of getting that to FID. So we wouldn't see any material spending until probably '23.

Our next question is from Pearce Hammond with Piper Sandler.

I just had one question today. Mackie, as you look out over the next few years at NGL supply demand, when do you see a need for more fractionation capacity at Mont Belvieu?

Well, what a great question, and we are positioned to capitalize on that when we find the answer to that question. We’re being very capital disciplined, so we have not completed our 8 frac, but we’re certainly watching it very closely, both for volumes that are committed to our plants and also volumes committed to third-party plants. So just from -- looking from our eyes intra transfer eyes, we don’t see the need for one for at least the next 6 to 9 months, but we evaluate on a quarterly basis. And we do expect that at some point in 2022, we’ll have to take a serious look at completing that 8 frac. We do expect the volumes to begin growing as long as commodity prices continue to stay where they are now. It sure looks like they will.

Our next question is from Christine Cho with Barclays.

I just wanted to -- how should we think about costs going up in ‘22 on the O&M and G&A side? And then do your inflation trackers have any caps to them? And to the extent that it tracks something like a CPI or PPI, should we think that -- should we assume the entire increase will be reflected in rates next year? Or would competitive pressures limit some of that -- the increase that you would actually put through?

I can start on the second half of that, which maybe most of it. Yes, in most of our contracts, certainly, in all of our liquid contracts around our transportation and fractionation and around our crude contracts, we have an index. It's typically a FERC index. But to give you an example, I believe the FERC index this year, I believe that started in July and it goes July to the next July, was negative. So we actually didn't have any kind of uptick in that from -- while we see this inflation. However, what that sets up for is next July we expect that to move up significantly. We've heard as much as 5% or 6%, and we do have those increases in the vast majority of our rig contracts as well as in many, if not most, of our gas contracts. So we do have, whether it's the CPI index in our gas contract or the FERC index and our liquid contracts, we do have that in the majority of those, and we'll benefit from -- or at least not be harmed by the inflationary growth in costs.

And we should expect that you would put the entire increase through? Like the competitive pressures wouldn't preclude you from just doing a part of it?

It may on future contracts. But when I’m referring to all the existing contracts we have today to move products to our systems already have that language in it.

And then on the NGL segment, just curious, one of your peers had talked about doing incentive rates in the Permian. Curious if you guys did the same thing or if the segment was really just all optimization headwinds.

Yes. I'm not sure what an incentive rate is, what -- the rate we will do is the highest rate we can possibly get from our shippers from what the market will allow.

Well, I guess, would you say they trended lower quarter-over-quarter?

I’m sorry. So if you’re saying -- where the marketplace is, yes. The -- just like crude, just like natural gas for lease for a short period of time, NGL cross all has been overbuilt. Fortunately, much of the barrels that are -- that come to our system and that will come to our system in the future are already dedicated. But those barrels that are out there to tailgate of third-party facilities that we go out and try to get on a monthly basis, it’s gotten very competitive. The T&F prices are significantly lower than where they were years ago.

Our next question is from Michael Lapides from Goldman Sachs.

Look, we're 8 or 9 months removed from Winter Storm Uri. Can you give a little insight on what you're seeing in the contracting market for gas storage, especially in Texas, whether you're already entering significant new contracts and kind of taking a little bit of the -- maybe the margin upside but also the margin downside of spreads move around but getting more of a fixed fee payment and just kind of how the market for gas storage overall is moving after that event?

You bet, this is Mackie again. Yes, it' kind of a variety. We effected a lot more demand or a lot more desperate, I'd say, demand to come secure storage. We certainly have sold more storage than we did last year at much more favorable rates and also some swing rights to that. We are still in negotiations with a number of parties and power plants for swing service and storage service for this winter. But some of the companies had panicked or haven't -- don't seem as worried about it as we thought they would after what happened at Uri. But once again, we're well positioned whether or not we've already done as we have some new deals or we're positioned to be able to provide that service as they need it this winter.

Ladies and gentlemen, we have reached the end of the question-and-answer session. Now I would like to turn the call back to Tom Long for closing remarks.

Thank you all once again for joining us today and for your support, and we look forward to talking to you in the near future.

This concludes today's conference. Energy Transfer, thanks you for your participation. You may disconnect your lines at this time.