Good afternoon, ladies and gentlemen, and thank you for standing by. Welcome to the Energy Transfer Third Quarter Earnings Call. 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 remains 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 one-time $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 volume 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 one-time 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 the 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 segments. 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.

Please open the line up for our first question.

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 would 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 the 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.

Our target remains in the 4 to 4.5 range. However, as I mentioned before, we continuously evaluate our forecasts when making decisions. We consider our projections and where we anticipate leverage trends to go. This is more about an overall outlook than a fixed threshold. As a result, we feel confident in discussing the possibility of returning capital to our unitholders, whether through distributions or unit capital expenditures. I want to clarify that I meant this would start next year.

My first question is about the ethane markets. Specifically, we have approximately 280,000 barrels a day of cracker capacity that is expected to come online over the next 1.5 years. This will create significant demand for ethane volumes in the U.S. Could you discuss where you anticipate these ethane volumes will come from? Do you expect it to be mainly from underlying NGL growth, or will it be due to less ethane rejection? Additionally, do you see any possibility of reduced ethane exports as these new crackers start operating?

Chase, this is Mackie. That's a fantastic question. We appreciate inquiries like this because Energy Transfer is well-positioned to lead in both ethane and all NGLs. We were the first to export ethane to Canada, and we have expanded our export operations at Marcus Hook and Nederland. Our advantage is that we control a significant portion of the ethane we receive at the output of our frac. Unlike some competitors, we possess a substantial amount of ethane that is in high demand globally. Our team, along with RB, maintains ongoing discussions with companies around the world, including South America, Asia, Europe, and China. We anticipate growth in this sector. This year, we launched a satellite, and next year, a second frac will come online, allowing us to increase our volumes. We already have approvals for expansions of 70,000 and 140,000 barrels per day at Marcus Hook, and we're currently negotiating with customers to reach final investment decisions on those projects. Ethane and propane have promising futures, and we are excited to be in a position to engage 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?

This is Mackie. I want to follow up on that. We will address whatever comes from those plans and legislation once it's finalized and budgeted. For now, we're focused on our work in the fossil fuel sector. We play a crucial role in producing, transporting, fracking, exporting, and selling energy that contributes to living standards both here and globally. We are optimistic about our industry and believe in its long-term future. There is a growing demand for natural gas, particularly for propane and ethane, as well as ethylene and propylene, which are essential in daily life. While we stay aware of political developments and any potential tax impacts on our partnership, we don’t let those concerns dominate our focus. We’ll address them when necessary, but right now, we're committed to generating revenue for our unitholders.

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, I apologize for not fully understanding the question, but we are in a strong position to benefit both our revenues and the customers in Texas and Uri. As I mentioned, we are also prepared this year for any cold spells or significant pricing volatility. We are well equipped to meet the needs of customers in Texas and across the country.

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, which is partly due to the lower inventory balance we are maintaining compared to $67 million in the same quarter last year. Both of these figures represent gains, but you can see that's where the spread lies. Regarding the second part of your question, yes, the Bakken pipeline was included. And I might add that there is still ramping up. Was that your question, Keith, just to clarify, were you asking 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.

All right. Keith, addressing the first part of your question regarding the debt, we currently have $1.9 billion. On November 1, we will be paying $1 billion of that, and then on December 1, we'll settle the remaining $900 million. As these maturities approach, we will keep paying them down. If an opportunity arises to extend some of them, I won't rule that out entirely. However, for now, we are focused on paying down these maturities and even considering early payoffs as they occur. Regarding the second part of your question, we continue to have discussions with the Board on that front. I can't provide any definitive updates at this moment, but both share buybacks and distributions remain key topics for us. I want to emphasize that maintaining financial flexibility is a top priority.

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 expressed it well, and that's largely what we observed this year and what we're noticing heading into the next year. The major companies are significantly more cautious and are monitoring their capital much more closely compared to many of the independent firms. Consequently, around our assets, we are detecting increased activity and production from the smaller companies. However, some of the majors, particularly in the Permian Basin and the Northern Louisiana region, as well as in the Marcellus Utica, are beginning to bring rigs back in, as many are aware. Rigs in North Louisiana have increased by about 45% compared to a little over a year ago, and we are witnessing a similar growth trend in the Permian. There are still many drilled but uncompleted wells in the Permian that have yet to be finished, although several have been completed recently as we approach 2022. Therefore, we would characterize the situation around our system as consistent growth, not just a sudden increase in the first or second quarter but steady growth throughout the year in both rigs and volume in the Permian. We anticipate quicker growth in the gas sector in Northern Louisiana and notice a comparable gradual increase in the Eagle Ford region in South Texas. Yes. Tom Mason and his team are currently monitoring developments from Congress regarding the 45Q tax credit and other incentives related to renewable energy. As previously mentioned, our primary focus is on our assets, specifically our processing plants and treating facilities. We aim to capture carbon, whether independently, through partnerships, or by enabling others to capture it. We are also exploring carbon capture opportunities at our Northeast facilities, including the Marcus Hook facility, where preliminary studies indicate promising returns. We will continue to pursue these initiatives and are also investigating carbon capture projects in South Texas, which may be sequestered or tied to an ERR project. Our daily efforts involve exploring deals across various areas, such as black carbon, converting natural gas to gasoline, and producing renewable diesel for transportation through our diesel pipelines. Although we are not making capital investments in solar projects, we are committed to purchasing affordable renewable power, supporting renewables in that manner. We will pursue feasible projects and anticipate finalizing some in the future, with potential investments of up to $20 million or $30 million in CO2 sequestration efforts. This will remain a priority as we move into 2022 and beyond.

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 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?

This is Mackie. Before the recent 42-inch pipes that came online in the past couple of years, transporting gas across the state was our main focus. We experienced spreads of $1.50 to $2, but those began to decline. Therefore, a couple of years ago, we implemented a strategy to secure longer-term commitments at favorable spreads, rather than settling for $1 or $1.50. In the third quarter, the average spreads increased to about $0.75 or $0.80. We secured commitments last year that affected this year's third quarter, which were lower than the current $0.75 or $0.80 but still significantly higher than today's spreads. This strategy was logical to us considering the potential short-term decrease in spreads. We anticipate that within 2 to 3 years, the basis will widen again due to increased demand, especially given the remarkable growth in the Permian Basin for natural gas. Meanwhile, we aimed to lock in some of our capacity at healthy margins for long-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. We've observed spreads decrease to between $0.20 and $0.30 recently. We believe, and the industry agrees, that over the next 1.5 to 2 years, these will start to increase again. We might see $0.75 or $1. Some competitors are discussing building additional 42-inch pipelines. We want to inform the market, along with producers and shippers, to consider our capacity before launching into any new projects, as we will have capacity available in 2 or 3 years. We would prefer to secure contracts at prices comparable to those of new greenfield projects. We are strategically positioned to navigate this period as all these 42-inch lines are completed, and as natural gas demand increases and fills them. Once they are at capacity, we will be in a strong position to capitalize on larger spreads with the capacity in 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 there would be any opportunity for a spike there. As you know, that’s a very small piece that sits up there. It’s a royalty business, so I wouldn't guide you toward anything there. As for divestiture, there are no plans or discussions happening regarding that.

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 has turned out well for us. A couple of months ago, we experienced a hiccup in Petco’s pipeline, yet we observed an increase in its value, especially considering the challenges associated with obtaining approval for another interstate pipeline in that area over the next few years. We are well positioned, with about 90% of our capacity under long-term contracts on a month-to-month basis. Often, we sell capacity at tariff rates, which vary based on whether the flow is directed up or down to Zone 1a. It is an excellently strategically located asset. With the increasing volumes from the Marcellus Utica, it has the unique capability to transport barrels north into Canada and all the way down to the Gulf Coast to supply LNG facilities and other markets. We typically move about 3.2 to 3.4, with a maximum capacity of around 3.55. We expect to see continued growth in both our capacity utilization and tariff rates as we look to the future. 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.

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?

That’s a great question, and we're ready to take advantage of that once we find the answer. We're being very disciplined with our capital, so we haven't completed our eighth frac yet, but we are monitoring it closely for both volumes committed to our plants and those dedicated to third-party facilities. From our perspective, we don't see a need for one within the next 6 to 9 months, but we will reassess on a quarterly basis. We do anticipate that at some point in 2022, we will need to seriously consider completing the eighth frac. We expect volumes to start increasing as long as commodity prices remain stable, and it appears they will.

I just wanted to know how we should think about costs increasing in 2022 for O&M and G&A. Also, do your inflation trackers have any caps? If they track something like CPI or PPI, should we assume that the entire increase will be reflected in rates next year? Or would competitive pressures limit some of the increase that you would actually implement?

I can address the second part of your question. In most of our contracts, particularly those related to transportation, fractionation, and crude, we have an index, usually based on the FERC index. For instance, this year's FERC index, which began in July and runs until the following July, was negative, meaning we didn't see any increase in light of current inflation. However, we anticipate a significant rise by next July, with projections suggesting increases of 5% or 6%. We have similar adjustments included in most of our rig contracts, as well as in many of our gas contracts. Therefore, whether it's tied to the CPI index in our gas contracts or the FERC index for our liquid contracts, we are positioned to benefit from, or at least not suffer due to, the inflationary increase 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.

We're about 8 or 9 months past Winter Storm Uri. Can you provide some insights into the gas storage contracting market, particularly in Texas? Are you starting to enter into significant new contracts and balancing the potential margin gains and losses due to fluctuating spreads, while securing more fixed fee payments? How is the overall gas storage market evolving after that event?

This is Mackie speaking. We've seen an increase in demand for secure storage compared to last year, and we are achieving more favorable rates alongside some flexibility in agreements. We are currently in discussions with several companies and power plants regarding swing service and storage for the upcoming winter. Interestingly, some companies seem less concerned than we anticipated following the events of Uri. Nonetheless, we are well-prepared to provide the necessary services this winter, whether through our existing arrangements or new deals.

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.