Greetings, and welcome to the Energy Transfer Fourth Quarter Earnings Results Conference Call. [Operator Instructions] Please note that this conference is also being recorded. I will now turn the conference over to our 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 Fourth Quarter 2021 Earnings Call, and thank you for joining us today. I'm also joined today by Mackie McCrea and other members of our 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 annual report on Form 10-K for the year ended December 31, 2021, which we expect to be filed this Friday, February 18. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both 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 fourth quarter and full year 2021 highlights. For the full year 2021, we generated adjusted EBITDA of $13 billion, which was a significant increase over 2020 and in line with our expectations. DCF attributable to the partners of Energy Transfer, as adjusted, was $8.2 billion, which resulted in excess cash flow after distributions of approximately $6.4 billion. On an incurred basis, we had excess DCF of approximately $5 billion after distributions of $1.8 billion and growth capital of approximately $1.4 billion. On January 25, we announced a quarterly cash distribution of $0.175 per common unit or $0.70 on an annualized basis, which represents a 15% increase over the previous quarter and represents the first step in our plan to return additional value to unitholders. Operationally, we moved record volumes through our NGL pipelines and NGL and refined products terminals for the full year 2021, primarily driven by growth in volumes through our Nederland terminal and on our Mariner East pipeline system. In addition, NGL fractionation volumes reached a new record during the fourth quarter, largely driven by growth in volumes leading our Mont Belvieu fractionators. At our Nederland terminal, we completed expansions in early 2021 that brought our company-wide total NGL export capacity to more than 1.1 million barrels per day which we believe is the largest in the world. On December 2, 2021, we completed our acquisition of Enable Midstream Partners, which provides increased scale in the Mid-Continent and Ark-La-Tex regions and improved connectivity for our natural gas, crude oil and NGL transportation customers. The combination of Energy Transfer's and Enable's complementary assets will allow us to continue to provide flexible, reliable and competitive services for our customers as we pursue additional commercial opportunities utilizing our improved connectivity and expanded footprint. We continue to expect the combined company to generate more than $100 million of annual run rate cost savings synergies, of which we expect to achieve $75 million in 2022. In addition, we are in the process of identifying and evaluating a number of commercial and operational synergies that are expected to enhance the operational capabilities of our systems by capitalizing on improved efficiencies and increasing utilization and profitability of our combined assets. Before moving to a growth project update, I want to briefly touch on the recent winter weather conditions seen across many of our assets. This out of winter weather was less severe and significantly less disruptive than winter storm Uri last year, and commodity prices remained much more stable throughout as a result. As we always do, we have procedures in place to provide layers of protection and risk mitigation, including engineering controls and winterization processes and preplanning and prepositioning of resources to assure, we are able to respond when needed. Our extensive experience with operating pipelines, processing plants and storage facilities combined with a significant amount of preparation allows us to operate reliably throughout extreme weather conditions, and this is due to the consistent and extraordinary efforts of our employees. I'll now walk you through recent developments on our growth projects. Starting with Mariner East Pipeline system. Construction of the final phase of the Mariner East pipeline is complete and commissioning is in progress which will bring our total NGL capacity on the Mariner East pipeline system to 350,000 to 375,000 barrels per day, including ethane. Energy Transfer's Mariner East pipeline system now includes multiple pipelines across the state of Pennsylvania, connecting the prolific Marcellus and Utica shales to markets throughout the state and the broader region, including Energy Transfer's Marcus Hook terminal on the East Coast. For full year 2021, NGL volumes through the Mariner East pipeline system and Marcus Hub terminal are up nearly 10% over 2020. With our expanded network, we will see volumes continue to grow. In our Pennsylvania Access project, which allows refined products to flow from the Midwest supply regions into Pennsylvania, New York and other markets in the Northeast started flowing refined products in January. At our expanded Nederland terminal, NGL volumes continued to increase during the fourth quarter, including export volumes under our Orbit ethane export joint venture, which have remained strong. For the full year 2021, we loaded nearly 26 million barrels of ethane out of the facility. For 2022, we expect to load a minimum of 40 million barrels of ethane and project this to increase to up to 60 million barrels for 2023. We also expect our LPG export volumes at Nederland to continue to grow in 2022. And in total, our percentage of worldwide NGL exports has doubled over the last 2 years, capturing nearly 20% of the world market, which was more than any other company or country exported during the fourth quarter of 2021. At Mont Belvieu, we recently brought online a 3 million-barrel high-rate storage well, which increases our total wells to 24 and our NGL storage capabilities at Mont Belvieu to 53 million barrels. Turning to our Cushing South pipeline. In early June, we commenced service on the 65,000 barrels per day crude oil pipeline, providing transportation service from our Cushing terminal to our Nederland terminal, which also provides access for Powder River and DJ Basin barrels to our Nederland terminal via 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 nearly double the pipeline's capacity to 120,000 barrels per day. Phase 2 is expected to be in service by the end of the first quarter of 2022 and is underpinned by third-party commitments. As a reminder, minimal capital spend was required for this phase. Next, construction on the Ted Collins link is progressing and is now expected to be completed late in the first quarter of 2022. The Ted Collins link will increase market connectivity for our Houston terminal. It will also give us the ability to fully load and export WTI barrels as well as low gravity Bakken barrels out of the Houston market, demonstrating Energy Transfer's unique capability to provide a neat Bakken barrel to markets along the Gulf Coast. 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 continues to be significantly utilized. This project allows us to move approximately 115,000 Mcf per day of rich gas out of the Midland Basin and to utilize available processing capacity more efficiently, while also providing access to additional takeaway options. In addition, an expansion is underway, which will bring the top line's total capacity to over 200,000 Mcf per day in the first quarter of 2022. And due to significantly increased producer demand, we now plan to build a new 200 MMcf per day cryogenic processing plant in the Delaware Basin. The Gray Wolf plant is supported by new commitments and growth from existing customer contracts and is expected to be in service by the end of 2022. In addition, to provide incremental revenue to our Midstream segment, once in service, the volumes from the tailgate of the plant will utilize our gas and NGL pipelines for takeaway, providing 3 revenue streams. Now in order to address the growing need for additional natural gas takeaway from the Permian Basin, we are diligently evaluating a takeaway project that would utilize existing energy transfer assets along with new build pipeline providing producers with firm capacity to the premier markets of Katy, Carthage, Gilles and Henry Hubs. This pipeline project would include the construction of a new approximately 260-mile pipeline from the Midland Basin to our existing 36-inch pipeline Southwest of Fort Worth, parallelly existing right of way. From there, it would interconnect with our existing assets with available capacity for delivery through our vast pipeline network to markets at Carthage as well as the Katy, Beaumont and the Houston Ship Channel and other markets along the Gulf Coast, including deliveries to the Gilles and Henry Hub. We view this project as an ideal solution for natural gas growth out of the Permian Basin that we can complete much more quickly than our competitors' options at significantly less cost about following an existing right of way along the majority of the route. In addition, it is aligned with our strategy of identifying and repurposing underutilized assets in order to maximize the value of our uniquely positioned existing asset base. Customer discussions are underway as we pursue this project. Given the proposed route and our ability to utilize existing assets, we believe we could complete construction of project in 2 years or less once we have reached FID. Turning to the Gulf Run Pipeline, which will be a 42-inch interstate natural gas pipeline with 1.65 Bcf per day of capacity. Gulf Run is backed by a 20-year commitment from Golden Pass LNG and will provide natural gas transportation between the Haynesville Shale and the Gulf Coast, connecting some of the most prolific natural gas-producing regions in the U.S. with the LNG export market. Pipeline construction is underway and is expected to be completed by the end of 2022. Lastly, in July of 2021, we announced the signing of a memorandum understanding with Republic of Panama to study the feasibility of jointly developing a proposed Trans-Panama Gateway Pipeline. We anticipate working closely with Panama to successfully bring this project to fruition. Panama's geographic location and favorable investment climate make this an attractive project. We continue to believe this project will 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. In January of 2022, we announced that we expanded our Alternative Energy Group through the hiring of a Vice President of Alternative Energy. This role is responsible for developing Alternative Energy and carbon capture projects for Energy Transfer, along with various ESG initiatives, including the development of carbon capture offset programs that are accretive to our operations. In addition to the 2 solar projects we announced in 2021, we are also continuing to explore several opportunities for solar, wind and forestry carbon credit projects on our existing acreage in the Appalachian region. We remain in discussions with other large renewable energy developers. On the carbon capture front, we continue to pursue our carbon capture project at Marcus Hook that would involve capturing CO2 from the flue gas and delivering it to the customers for use in the food and beverage industries. This project looks financially attractive based upon preliminary cost estimates and design feasibility studies. We are also pursuing several carbon projects related to our assets, including projects involving the capture of CO2 from processing and treating plants for use in enhanced oil recovery for 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 published our annual corporate responsibility report to our website in December. Now let's take a closer look at our fourth quarter results. Consolidated adjusted EBITDA was $2.8 billion compared to $2.6 billion for the fourth quarter of 2020. DCF attributable to the partners, as adjusted, was $1.6 billion for the fourth quarter compared to $1.4 billion for the fourth quarter of 2020. For the fourth quarter, we saw higher transportation volumes across all of our segments, including record volumes in the NGL and refined products segment as well as a $60 million adjusted EBITDA contribution from the acquisition of Enable for the month of December. On January 25, we announced a quarterly cash distribution of $0.175 per common unit or $0.70 on an annualized basis. This distribution will be paid on February 18 to unitholders of record as of the close of business on February 8. This distribution represents a 15% increase over the previous quarter and represents the first step in our plan to return additional value to unitholders while maintaining our leverage ratio target of 4 to 4.5x debt to EBITDA. Future increases to the distribution level will be evaluated quarterly with the ultimate goal of returning distributions to the previous level of $0.305 per quarter or $1.22 on an annualized basis while balancing our leverage target, growth opportunities and unit buybacks. Turning to our results by segment and starting with NGL and refined products. Adjusted EBITDA was $739 million compared to $703 million for the same period last year. This was primarily due to higher transportation and terminal services margins related to increased throughput at our Nederland terminal in the fourth quarter of 2021 as well as increased fractionation in refinery services margin. NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record 1.9 million barrels per day compared to 1.4 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 Permian and Eagle Ford regions as well as increased volumes on our Mariner East pipeline system. And our fractionators also reached another record for the quarter. With average fractionated volumes of 895,000 barrels per day compared to 825,000 barrels per day for the fourth quarter of 2020. For our crude oil segment, adjusted EBITDA was $533 million compared to $517 million for the same period last year. This was primarily due to higher crude oil transportation volumes out of the Permian Basin improved volumes through our Nederland terminal and improved performance on our Bakken and Bayou Bridge pipelines as a result of recovering volumes in the fourth quarter of 2021 and the addition of the Enable assets. For Midstream, adjusted EBITDA was $547 million compared to $390 million for the fourth quarter of 2020. This was primarily due to a $147 million increase related to favorable NGL and natural gas prices. In addition, our Midstream segment also benefited from growth in the Permian, South Texas and Northeast and the acquisition of the Enable assets in December 2021. Gathered gas volumes were 14.8 million MMBtus per day compared to 12.6 million MMBtus per day for the same period last year due to higher volumes in the Permian, South Texas and Northeast regions as well as addition of the Enable assets in December of 2021. Permian Basin volumes continue to be strong and Midland volumes remain at or near record highs. As a result, we are expanding our Permian Bridge project and constructing our new Grey Wolf processing plant in the Delaware Basin. In our Interstate segment, adjusted EBITDA was $397 million compared to $448 million in the fourth quarter of 2020. While volumes are beginning to improve, we did experience contract expirations at the end of 2020 on Tiger and FEP. And due to very mild temperatures throughout the Midwest, we experienced lower demand on our Panhandle and Trunkline systems during the fourth quarter. However, these decreases were partially offset by increases on Rover and Tiger due to more favorable market conditions and to significant volume growth out of the Haynesville. These results also include the Enable assets in December of 2021. We have seen steady growth recently in the Interstate segment with the fourth quarter up more than 10% over the third quarter of 2021 even without the impact of Enable. For our Intrastate segment, adjusted EBITDA was $274 million compared to $233 million in the fourth quarter of last year. This was primarily due to increased firm transportation volumes from the Permian and South Texas, the recognition of certain revenues related to winter storm Uri and an increase in retained fuel revenues due to higher natural gas prices as well as the addition of the Enable assets in December of 2021. Now turning to our 2022 adjusted EBITDA guidance. With expectations for continued strong performance from our existing business as well as the addition of the Enable assets, we expect our full year 2022 adjusted EBITDA to be $11.8 billion to $12.2 billion. And moving to our 2022 growth capital expenditures. We expect growth capital expenditures, including expenditures related to the recently acquired Enable assets to be between $1.6 billion and $1.9 billion, balanced primarily across the midstream NGL and refined products in Interstate segments. This number includes approximately $200 million of 2021 planned capital that has been deferred into 2022 as well as growth capital related to the recently acquired Enable assets, in particular, Gulf Run pipeline. In addition, this includes newly approved projects in the Permian Basin that support growing natural gas production through new gathering and processing capacity, improved efficiencies and reduced emissions. These projects include construction of a new processing plant optimization of the Oasis pipeline and modernization and debottlenecking of the existing system. The majority of these new projects are expected to provide strong returns and be completed at a 6x multiple on average. Now looking briefly at our liquidity position. As of December 31, 2021, total available liquidity under our revolving credit facility was slightly over $2 billion, and our leverage ratio was 3.07% for the credit facility. During the fourth quarter, we utilized cash from operations to reduce our outstanding debt for approximately $400 million. And for full year 2021, we reduced our long-term debt by approximately $6.3 billion. We expect to generate a significant amount of cash flow in 2022, which will be strategically allocated in a manner that best positions us to continue to improve our leverage, invest in the growth of the partnership and return value to our unitholders. As we approach our leverage target range, we have taken our first steps toward returning additional capital to our equity holders through distribution growth, which we will continue to evaluate on a quarterly basis. In addition, we have increased our growth capital spend, as I mentioned earlier on the call, with this capital focused on strong returning projects that will be in service in less than 12 months. And we expect to continue to pay down debt throughout the year with excess cash flow from operations. During the fourth quarter, we continue to see volumes recover across many of our systems, including another record quarter for volumes in our NGL and refined products segment. Looking ahead, we are excited about the opportunities in front of us. We will continue to explore and implement commercial synergies around the recently acquired Enable assets. And we continue to see growth across our NGL business segment, driven by increasing demand, both domestically and internationally. We have entered 2022 with a much stronger balance sheet than 2021, and we'll continue to place emphasis on financial flexibility and pay down debt in 2022 while continuing to position ourselves to return value to our unitholders. Given the volume growth expected out of the Permian Basin, we have some attractive new projects underway that will address new demand, enhance the efficiency and flexibility of our existing asset base and generate attractive returns above our target threshold. We also continue to make progress on the alternative energy front, which can further enhance and effectively grow our Energy franchise. Operator, please open the line up for our first question.

[Operator Instructions] And our first question comes from Michael Lapides with Goldman Sachs.

Congrats on a good end of year and good quarter. Actually, I had 2. One is, in the potential development of a takeaway solution for natural gas coming out of the Permian, can you talk a little bit about just what the early feedback from shippers has been? Meaning, what's the level of interest in shippers to sign a 10 or 15-year contract? Or are they more willing to do and want to do shorter-term deals? That's the first question. And then the second question is, can you just talk a little bit about the Permian Express system and where you might have recontracts, contracts that roll off over the next couple of years?

You bet, Michael. This is Mackie. We are so excited about this project. We haven't really spoken a lot about it. We have more capacity than anybody else now across the states. We've been accommodating volumes growth for the last year or 2. We've heard a lot of our competitors talk about a project, how needed it was, how close they were to getting a project online. And it really became important over the last number of weeks that we kick in, in a big way. And so to answer your question, the customers that we talk to are very excited. If you compare our project to anybody else, most of them have gone either from the Waha area down to [indiscernible] or now they're talking about going to Katy and the luxury of what our project will provide will be just kind of a smorgasbord of markets. And we've said in the statements by Tom earlier, but the bottom line is we will take Permian Basin molecules and deliver them to the best markets on the Gulf Coast to Katy, to ship channel, to some of the LNG markets, to Henry Hub to Gilles and the better markets in Louisiana. Some of these producers can stop or shippers can stop in Carthage. So we're extremely excited about this. We continue to do what we've been doing for a long time, and let's look at all of our assets and not only how we repurpose them possibly to make more revenue, but also how we use more efficiently and utilize them in a better way. And this project will allow that. It's probably a 200-mile less pipeline than our competitors. It will tie into 36- and 42-inch pipelines downstream, where we have a significant amount of capacity, they will need to -- say we're very excited in the customers we've spoken to are as well. In regards to Permian Express, spread, as everybody knows, have fallen off dramatically over the last couple of years. The -- as the industry does commonly, we go through the cycle of over building. And clearly, the crude side of our business is overbuilt. As we always say, though, we feel very fortunate that we have assets that reach out all the way to the wellhead and we don't stop it in Houston now or Nederland or Bayou Bridge or put barrels on the water and even deliver through our Mid-Valley system up in the Mid-Continent. So we can often more than any of our competitors, and our teams at the results have shown this quarter have done a fantastic job of keeping Permian Express full and growing them. Our volumes fall off to the pandemic. We grow significantly fourth quarter over fourth quarter that we just showed in our results. And so yes, contracts have rolled off over the last 2 or 3 years. We're not looking at locking in long-term contracts right now where the spreads are, but we'll see this production start to increase over the next 2 or 3 years, and we'll certainly capitalize on the spreads as they move out. But in the meantime, we're all for this string of services from the wellhead all the way to loading on ships or to refineries, and we're pretty excited about our true growth business through these assets.

And our next question comes from Chase Mulvehill with Bank of America.

Just a follow-up question here. If we think about the potential capacity of the pipelines coming out of the Permian or the natural gas coming out of the Permian, how much capacity do you think you'll be able to kind of pull out of there and get to the Gulf Coast as you look at these conversions for this Permian nat gas takeaway projects?

The way we're going to look at that is, of course, listen to our customers and we'll design a system that can meet those demands. But what we anticipate is kind of a minimum of combined capacity that we have today on Oasis that's available today and in the future. And with this new pipeline project, we'll have a target between 1.5 and 2 Bcf of new takeaway capacity, a couple of years after we reach FID.

Okay. All right. That makes sense. And you said, once you reach FID, to take you kind of 2 years to put it in service, and it seems like it's early stages, maybe conversations with customers. So maybe we're a few months away from FID. And if we kind of look forward 2 months, where $90 crude is going to incentivize a lot more activity in the Permian. It's only going to pull this bottleneck forward, not push it to the right. So it's probably going to happen even faster than people think. And so we reach that point of constraint for natural gas takeaway capacity earlier in the Permian in 2023. So maybe walk us through your Permian business and help us understand the puts and takes, where you can make more money and where it might hurt you if you hit some bottlenecks for nat gas takeaway in the permit?

Okay. Yes. Look -- and we've spoken about a few of these projects. We are in the middle of the project right now where we're spending on a great deal of capital, and we're increasing the capacity on Oasis by between 40,000 and 45,000 a day. We're looking at another expansion where we can increase it by about another 20,000. So -- and we should kick that off pretty soon. Not a lot of capital, just adding compression, and we'll be able to move about 60,000 more a day. So to your question about it could move forward more quickly, we agree with that, we think if you look at some of the forward curves, you're out over $1, $1.20, I think, latter part of '22 and '23, and we're well positioned to capitalize on that. We have capacity on Oasis. We have more capacity coming available in the next couple of years on contracts that are rolling off at much lower rates than where we think the market will be. So we positioned ourselves very well. So we're kind of capitalizing in 3 different ways. One, on what we have today, wherever the spread is, we're, of course, benefiting from that. We're adding capacity where it makes sense, and I just alluded to on the 60,000 that would be adding here the next 6 or 7 months. And then once we hopefully get to FID here in the coming quarters, then we'll add additional takeaway. But there is going to be some tough time regardless of the decisions late for whoever it's going to build the next pipe, and we do believe there is going to be a blowout spreads, and we're sitting in a very good spot there because where our assets are in the available capacity we have to move Permian Basin volumes to the Gulf Coast.

Next question comes from Jeremy Tonet with JPMorgan.

I just want to start off with the CapEx, if I could? I was just wondering if you could help us bridge, I guess, the $500 million to $700 million guide before to now? And any numbers you could put around how much was Enable versus new projects? Just trying to better understand the drivers there.

Okay. Yes. Jeremy, this is Tom. One, will I start first with the split of how the numbers are coming out between the various segments. And I appreciate the fact that Gulf Run is now included in this. But the largest piece of this is really earmarked toward the midstream. You heard us talk about like the new processing plant. So that's probably about 35%, 36% of the number. Then moving next, you're going to move into the interstate with the Gulf Run that I just mentioned, you're probably running about 20%, 23% or so on that piece of it. And then when you keep moving on down through the mix, the NGL and refined products are 20%, 21% with crude intrastate and other kind of bringing up the last of it. But that's the way you really kind of see it. Now kind of looking at this, remember that we did roll over a couple of hundred million from projects and in 2021. So we probably need to start with that. As far as the rest of the pieces of it, that's really how it's probably best to try to break that out. I don't really have a bridge necessarily between the $700 million to these numbers. But I would say the biggest chunk of that is coming in with the Gulf Run.

Got it. That's helpful there. And I just want to turn to Enable for a minute, if I could? Just wondering now that you have them in the fold for a little bit here, wondering how things are going versus expectations? And really, I just wanted to see, you talked about converting assets like for this potential new Permian gas pipe project, do you see, I guess, more potential conversions now that you have kind of a larger set of assets to work with here?

Yes, Jeremy, we do. We're very excited. As we've said before, we hadn't really dug into the commercial synergies. We knew they were there. We saw some kind of easy ones. But as we've dug in, we found more. There's a number of ways where we can run plants more efficiently. There's pipelines that we're looking at, we can convert them to a different product, particularly NGL in a couple of instances. And we're also looking at combining assets and pipeline assets to move volumes out of Haynesville and into some of the markets to get gas fill -- our assets to the Gulf Coast. So still a little bit early. We'll talk much about those, certainly by our next earnings call will be knee deep and announcements and taking advantage of some of those synergies, but we're very excited with kind of a very preliminary discussions and analysis that we've been going through, but we do have teams working on that daily.

Our next question comes from Michael Blum with Wells Fargo.

Just wanted to follow up on some of the Permian gas discussion. Just to confirm, the Oasis pipeline optimization project that you referenced, is that the 60,000 expansion that, Mackie, you were talking about? Or is that the limit as to what Oasis can be expanded?

Mike, it's Mackie. Yes, gosh, limit. We've seen like we've gone through this exercise, I don't know, for years, and we keep adding capacity. And as we study more, we find ways to add more. So the more recent one was the one I mentioned, too, that we're already moving forward on the 40,000-plus -- 40,000, 45,000 Mcf day expansion of ad and compression, and then we're about to approve another smaller one, but a 20,000. So combined, that's about 60,000 or 65,000 of additional capacity that we'll have added by the end of the year, first part of 2023. So that's separate from this other project that we're talking about out of the Midland Basin, a much bigger project to move gas to existing assets that we own over closer to East Texas.

Okay. Great. And then on this new project, I think you mentioned you'd have to convert some existing pipelines. Would you -- what service would you be taking those out of? And the second part of that question is for the -- this new larger pipeline, what length of contract will you need to sort of get this thing to FID?

I'll start with the end of that. Our goals on these types of projects are typically 10 years, so that's what we'll be negotiating a lot depends on the rates and what exactly the customer is looking for. So we'll be negotiable on that. But to clarify, no on this one, unlike all the others converting crude oil to gas or gas to NGLs or NGLs to diesel. This is just utilizing capacity that's underutilized today. So for example, we would be tying this project into a 36-inch pipe near Tolar, which is southwest of the Metroplex, DFW Metroplex, and that would tie into our massive intrastate 36, 42-inch pipeline systems that deliver enormous amounts of gas all over the Carthage and all the way down into the Gulf Coast, Katy and into the ship channel markets as well as the Beaumont markets. So we're not converting any capacity on this project. It's just fully utilized capacity. It's already built sitting there idle underutilized.

Our next question comes from Jean Ann Salisbury with Bernstein.

The Haynesville is growing rapidly and several new projects have been proposed. Can you kind of comment on if you think Haynesville will run out of capacity kind of before Gulf Run comes on? And are you close to moving forward on the expansion project to Gulf Run?

Yes. I'll step back a little bit. Yes, our team, [indiscernible] and her folks, have been working hard on finding a solution for the growth out of the Haynesville. So we've done that in a number of ways by bringing gas in from Tiger into Carthage and moving it to our HPL and ETC network down into the Gulf Coast. We've done some significant contracts there. We're negotiating some very significant ones that provide access and flexibility where some of these producers are looking to go east to Perryville and Tiger and also come back into Texas. At the same time, there's about 1.1 Bcf of Golf Runs already sold. So we've got about 500-plus, 550 that we're looking to sell. We're aggressively tying that into our conversations for those producers that would like to reach the markets at the end of Gulf Run. And in that now, as you can imagine, we're -- and the volume growth in the Haynesville is a tremendous volume growth. We'll need to increase Gulf Run, no doubt. And we'll be looking at doing that in the near future. In addition to that, as we move more gas Eastern on both our new CP line and on the Tiger line, we will be kind of upgrading our ability to move gas through trunk line down into the Henry Hub market into some of the LNG markets on the Gulf Coast. So Haynesville, huge growth for this country for natural gas growth and huge things that we can capitalize on with the assets we have, especially now that we own the Enable assets that run through that same area.

Great. That's super helpful. And then as a follow-up, you used to have significant exposure to the Waha differential, but then I think you firmed it all up. I'm not sure for how long. How much exposure would you have to the differential in '23 '24? And it looks like it might widen again. I know you kind of mentioned you could optimize Oasis, so perhaps that could be part of it. But on the underlying Oasis, just wanted to see if you still had open capacity?

Yes. We have -- we did have a strategy a while back of, we were very fortunate to be able to benefit from the spreads when they blew out. But during that time, we knew they'd come back in. So we did go in and carve out some of that capacity as our shippers requested and put some of those contracts in place, long-term 5, 7, 10-year contracts. But we still have several hundred thousand in excess of several hundred thousand a day of capacity across the state. And over the next year or 2, we'll have more capacity becoming available, like probably at least double that amount. So 400,000 to 500,000 in the next year or 2 will have to benefit from these wider spreads and/or benefit from those shippers that are wanting to take capacity under a 10-year deal on a new project, they may start out on Oasis for part of that time in the early years and then move them over to the bigger projects. So it just gives us kind of a significant advantage over all the competition and be able to accommodate the needs over the next year or 2 and then gives us time to build a much bigger diameter pipeline to meet the needs that we all see coming by '24, '25.

Our next question comes from Timm Schneider with Citi.

And actually, let me follow up on the contracting question on the new -- on the potential new Gulf Coast gas pipeline. Any appetite here to maybe do this even if you don't get the 10-year commitments right off the bat because you are going to, assuming this is the most cost-efficient project out there, going to be making a lot of money potentially on spreads. How do you think about that?

I'm sorry, I missed the first part of that question. Say that again. I'm sorry, Timm.

Yes. So I was just asking what the appetite was for you guys to potentially go ahead with this project even if you don't have 10-year contracts from shippers given the fact that it's probably the most cost efficient and you'd be making a lot of money on spreads as is anyways?

Yes. As we've said, one thing we are going to do even in light of how needed this is, we're going to be very prudent on our capital. And so we're going to make decisions that make sense both short term and long term. But we do believe because of the advantages that I've talked through and that you all are aware of that we have a significant advantage to kind of get this moving very quickly. And so we do believe that whether it's 7-year contracts at higher rates or 10-year terms at a little bit lower rates. We believe we're going to achieve those. We really, at this point, don't see any like major players stepping up 600,000 a day. We do think this can be made of a whole lot of different shippers and producers. But once again, I think as we get the word out and we have the number of customers, everybody is going to see a clear advantage that this project offers is significantly better than any of the competing pipeline projects that are out there.

Got it. And then a follow-up on the CapEx side. And Tom, I think you kind of talked about this in prepared remarks. The increase in CapEx, that is primarily going to be very short -- not very short cycle, but shorter cycle CapEx, where a lot of that is actually going to show up in 2022 EBITDA. Is that the right way to think about that?

Yes, that is the way to think about it. That's the real beauty of a lot of this CapEx. It is very short nature. And I'm not saying it won't be until kind of later 2022. So 2023 is probably when you'll see the full impact. But you stated it properly when you said that these are shorter build type, good returning projects.

All right. And then maybe the last one here. What are the book – I mean, the book ends 11.8 billion to $12.2 billion on the EBITDA. What are some of the moving pieces around that? A –Mackie McCrea: Yes. I’m not sure if I understand your question completely. If you’re talking – I mean some of it, Timm, is commodity prices. Commodity prices stay higher, we’ll be on the higher end or they go higher than there are today. If we see commodity prices drop off, that would tend to move a little bit off of the high end. So that’s one of the drivers. And then spreads kind of watch and see what happens with spreads. And we think that as we’ve seen in the gas, these were down the teams not that long ago, and now we’re starting to see them spread out. And as I’ve mentioned a little bit earlier, as you get deeper in this year, they’re going to spread out significantly. So we’ve made certain assumptions on those spreads. However, we’ve been very conservative along those lines. So I guess I’d summarize all that with commodity prices certainly will have an impact, but also we do believe that the drilling is returning in a big way. The rigs have even moved back into Oklahoma. We were talking a little bit earlier today that the rigs pre-pandemic in the first part of 2020 are now back to I think equal, maybe a little bit more rigs in Oklahoma, which everybody is aware they moved back in, in a big way. So there’s assumptions that the industry is going to continue to grow as the pandemic leave the world as demand grows for all these products. And so we’re very bullish on drilling to continue. And so that plays a role into our projections as well. A –Tom Long: And the one thing that I would add is the commodity piece of this is, as far as the exposure, we’re using about 7.5% to 10%, and we’re using 0% to 2.5% on the spreads. So 90% fee-based. And when you add those others together, they add up to about 10%. So that’s how you can calibrate that commodity and spread component.

Our next question comes from Spiro Dounis with Credit Suisse.

First one is just on the distribution. Curious how you guys are thinking about the time frame or maybe the pace on getting back to that prior distribution of $1.22 -- sorry, $1.22 a year? It sounds like leverage may be one of the governing factors there to some degree. And the other factor you mentioned, of course, is the pace of buyback. So just curious how you're weighing all that and just how to help us think about the pace of getting back to that prior level?

Yes. We really are focusing on the points that you just walked through there. So if you really look at this, returning to the -- at least the $1.22 that we talked -- that we had previously, back before we had reduced the distributions, that is moved up to a top priority, but we clearly have these great projects we're talking about, likewise, these capital projects, then you blend in the debt paydown likewise. Unit buybacks, I would probably put as behind those 3.

Got it. That's helpful. And then, Mackie, just putting all your comments together, just around the Haynesville, clearly, more gas coming there, this new natural gas pipeline out of the Permian. You're trying to move that gas. It sounds like as far east as you possibly can. All seems to be getting to a point where maybe Henry Hub very clearly can be well supplied for a long time. So I'm sort of curious what does that do for prospects on something like Lake Charles LNG? I saw that you guys had requested an extension there for construction recently. So I don't want to tie them together too much, but just curious where that sits commercially, got I think moving more gas towards Hub is a good thing long term?

Yes. It's a great question because, for example, one of the larger shippers that possibly could take a fairly significant amount of gas compared to the others on this project wants to get to Henry Hub and would love to be a provider of gas to our LNG projects, our Lake Charles project. So that does kind of go hand-in-hand with some of the shippers and producers we're talking to. But around LNG, we've been through cycles of excitement and emotion over the last 4 or 5 years, whether we'll ever get there. And I'd tell you, it's really pick up steam. You read it anywhere. You see what's going on around the world and China from the top of their leader, their mandate is to go out and find gas. And we're seeing that with the Chinese customers as well as other customers. Around the world, there is a big push right now, that all of a sudden natural gas is green, and everybody's realized how important it is only for the next 5 years or the next 30 years. And so it's really picked up steam. We hope to be able to announce some agreements that we are close to getting signed over the next few years. They're certainly still ways from FID but we are really excited about where that project is going. And more importantly than not of where we may end up at the end of the day, what percentage we make under that. The biggest site we have what you just alluded to, and that's all the gas that we'll feed into the system into the Henry Hub area through our multitude of pipelines, through Golf Run, through Trunkline in both directions, bringing gas across CP, across Tiger, unlike all the other projects that are along the Gulf Coast, nobody can bring gas from Marcellus, Utica, through Panhandle, I mean, Rover Panhandle Trunkline directly into this project or now from Arkoma in Oklahoma Basin all the way down or even out from Permian. So it's turning to a really good project for the markets around the world, and then it has a by far the best supply portfolio and connectivity upstream. So we do believe that the Henry Hub area is going to become a much bigger trading hub than it already is and our LNG project would just magnify that significantly.

Our next question comes from Keith Stanley with Wolfe Research.

First, just a simple one. How many units of the company repurchased in Q4, the company itself, if any?

I think it was about $4 million.

$4 million. Okay. Great. Second one, Tom, you talked about debt reduction still being a priority for this year. Can you give a sense of, I guess, how you're looking at maturities and using free cash flow? Obviously, I mean you did over $6 billion of debt repayment last year. So as you see maturities this year, are you looking to use free cash flow to repay them generally? Or are you open to refinancing some of the debt as it matures.

Let's turn off with, we're clearly going to keep working towards the $4 million to $4.5 million. So as these maturities come up throughout the year, I would say that we will be paying down some of those maturities with free cash flow, but we will probably refi some of those maturities as they come up throughout the year.

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

Mackie, you mentioned seeing more drilling activity in Oklahoma. Now that you have the Enable operations in-house, can you just update us on your Mid-Con NGL strategy? And what sort of time line we should be thinking about to fully integrate those volumes into the ET value chain?

You bet. And as I mentioned, we have the teams little bit working on this daily to try to figure out a way to best utilize all of our pipelines, our processing plants. For example, there are some plants in the Panhandle that may make sense to initially or for a short period of time to shut those down and more [Technical Difficulty].

Please stand by. Thank you. Please go ahead, sir.

Can you all hear me?

Yes, sir. Go ahead.

Okay. So did you hear any of my answer? If not, I'll just start over -- we're not sure what happened. It just disconnected. But anyway, I'll do a shorter version. We do have teams working on this around the clock. We've already identified some opportunities to better utilize more efficiently some of our plants and some of our pipelines. Looking longer term, we are looking at converting a pipeline to potentially crude service. And then, of course, a lot of our folks is going to be utilizing existing pipelines and/or repurposing in other manners to get NGL barrels down into our Texas NGL franchise ultimately for deliveries to Mont Belvieu and of course, on the Gulf Coast into the export market. So we've got kind of a short-term vision of immediate things that we'll do to benefit the assets up in Oklahoma and then a longer-term vision of bringing us many of the NGL barrels into our system.

Great. And Mackie, maybe just to clarify that last point on bringing Oklahoma barrels down. Is that thought process over the next couple of years? Or is that more of a back half of the decade when those barrels might be available to you?

Without disclosing a whole lot, I guess, from a competitive standpoint, in the next 3 years or so, we do expect the demand to grow in our ability from a contractual standpoint to start moving more barrels from the tailgate of both plants and other plants in Oklahoma, even third-party plants into our NGL franchise for deliveries down to the Gulf Coast.

Perfect. And then maybe, Tom, switching back to the capital priorities. You mentioned buybacks sliding a bit lower in the stack versus some of the alternatives -- can you remind us how you all evaluate the return potential on buybacks versus new growth projects?

Yes. It's based upon what you what you look at from a DCF per unit standpoint, is how we really look at that, probably not as much from a distribution yield. And as we look at where the unit price is and where that breakeven is versus the other opportunities for some of the capital projects we've talked about today. But we do look at it from a DCF per unit standpoint. A DCF yield, let's call it that.

And that concludes today's conference call. We appreciate your participation. All parties may now disconnect. Have a good day. Thank you.