Hello, and welcome to the Energy Transfer First Quarter 2022 Earnings Conference Call. My name is Brandon, and I'll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct the question and answer session. As a reminder, this conference is being recorded. I will now turn the call over to Tom Long, Energy Transfer's Co-CEO. And Mr. Long, you may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer first quarter 2022 earnings call. 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 quarterly report on Form 10-Q for the quarter ended March 31, 2022, which we expect to be filed tomorrow, May 5. 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 first quarter highlights. We started the year off with a strong first quarter, where we generated adjusted EBITDA of $3.3 billion and DCF attributable to the partners of Energy Transfer, as adjusted, was $2.1 billion. This resulted in excess cash flow after distributions of approximately $1.5 billion. On an incurred basis, we had excess DCF of approximately $1.1 billion after distributions of $618 million and growth capital of approximately $390 million. On April 26, we were pleased to announce a quarterly cash distribution of $0.20 per common unit or $0.80 on an annualized basis, which represents a more than 30% increase over the first quarter of 2021. As a reminder, future increases to the distribution level will be evaluated quarterly with the ultimate goal of returning distributions to the previous level of $30.5 per quarter or $1.22 on an annual basis, while balancing our leverage target, growth opportunities and unit buybacks. Operationally, we have a brand franchise with assets in all the major producing basins in the U.S. and saw throughput increase in our segments as rig counts continue to improve across the U.S. In addition, we completed construction of several growth projects, which I'll provide more details on shortly. In March of 2022, we announced a definitive agreement to sell our 51% interest in Energy Transfer Canada for cash proceeds of approximately $270 million. In addition, the sale is expected to reduce our consolidated debt by approximately $450 million. This sale allows us to divest of these non-core assets at an attractive valuation and utilize the cash proceeds to further deleverage our balance sheet and redeploy capital with our U.S. footprint. The transaction is on track and expected to close by the third quarter of 2022. Also in March of this year, we completed a $325 million bolt-on acquisition of underground storage assets and an ethylene storage header that further enhanced our Mont Belvieu and Nederland positions. This acquisition of the Spindletop asset provides us with an exceptional ethylene storage and transportation header system located strategically between our Mont Belvieu and our Nederland terminals. The header system is connected to multiple ethylene pipeline customers. In addition, it has 2 active storage caverns, 1 cavern under development and the potential to develop at least 4 or 5 more storage caverns. We believe this system will play a major role in connecting ethylene supply in markets along the Texas and Louisiana Gulf Coast as we are seeing significant and unprecedented interest for many of the petrochemical players in utilizing not only the storage facilities, but also the ethylene header system. Now for a brief update on the integration of the Enable assets. 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. The majority of our back-office integration is complete, including integration of bank accounts, general ledger and treasury systems. We continue to identify and evaluate 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. This includes opportunities to run plants more efficiently, potentially converting pipelines to different products as well as optimizing our combined assets to provide customers on our enabled systems with access to premium markets further downstream through our vast energy transfer pipeline network. I'll now walk you through recent developments on our growth projects. In March, we announced that we have entered into 2 20-year LNG sale and purchase agreements for our Lake Charles LNG project with ENN Natural Gas and ENN Energy Holdings Limited. Under the 2 SPAs, ET LNG is expected to supply 1.8 million tonnes per annum of LNG to ENN Natural Gas and 0.9 million tonnes per annum of LNG to ENN Energy. On Monday of this week, we also announced the signing of a 20-year LNG purchase and sell agreement with a subsidiary of Gunvor Group for 2 million tonnes of LNG per annum. And yesterday, we announced the signing of another long-term LNG offtake agreement with SK Gas, an affiliate of the Korean conglomerate SK, for 0.4 metric tonnes per annum for a term of 18 years. The purchase price for all these agreements is indexed to the Henry Hub benchmark plus a fixed liquefaction charge and the LNG will be delivered on a free-on-board basis. The SPAs will become fully effective upon the satisfaction of the conditions precedent by ET LNG, including reaching FID. We are also in active negotiations with a number of other high-quality customers and we expect to make an announcement of additional offtake agreements in the weeks ahead. As we have previously stated, we expect to finance a significant portion of the capital cost of this project by means of the sale of equity in the project to infrastructure funds and possibly to 1 or more industry participants in conjunction with the LNG offtake agreements. We are currently targeting FID for this project in the fourth quarter of this year. Recent events in Europe highlighted the importance of LNG from the United States, a country with abundant natural gas supply and strong geopolitical ties to Europe. We are hopeful that our Lake Charles LNG project will be a significant factor in the long-term solution for global energy needs. Looking at the Mariner East pipeline system during the first quarter of this year, we completed construction of the final phase of the Mariner East pipeline, which brought our total NGL capacity on the Mariner East pipeline system to more than 365,000 barrels per day, including ethane. For the first quarter of 2022, NGL volumes in the Mariner East pipeline system and Marcus Hook Terminal remain steady. Since the end of the first quarter, we have seen an uptick in volumes through the pipelines and expect to see incremental revenue and volume growth for the remainder of the year. And 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 of this year. At our expanded Nederland Terminal, NGL volumes remained strong during the first quarter, including export volumes under our Orbit ethane export joint venture. For the first quarter, we loaded approximately 8 million barrels of ethane out of the facility. And for the full year 2022, we continue to expect to load more than 40 million barrels of ethane with that increasing to up to 60 million barrels for 2023. We also expect our LPG export volumes at Nederland to continue to grow in 2022. In total, we continue to export more NGLs than any other company or country and our percentage of worldwide NGL export remains at nearly 20% of the world market. We are seeing long-term increases in NGL demand and market value both here in the U.S. as well as internationally. We expect to participate in this growth as well as increase our market share as our franchise is uniquely well situated to benefit from this expanding market. We are seeing strong demand from overseas customers seeking additional supply from the United States, and we have recently secured sufficient commitments to move forward on the ethane expansion. Even though we expect to expand our ethane export capabilities at both Marcus Hook and Nederland Terminal terminals, these commitments provide us with the opportunity of expanding at either terminal. Therefore, we are evaluating which location would be best suited for our next ethane expansion project. We continue to evaluate the opportunity to develop a petrochemical project along the Gulf Coast. If we are able to reach FID, we believe that our cracker will be a very unique world-class facility, providing unparalleled access to the lowest cost feedstock through our pipeline systems, as well as unparalleled access to downstream domestic and international ethylene and propylene markets through our pipelines, our storage facilities and our export terminal. We're in discussions with a number of high-quality customers as we work to secure long-term tolling-type commitments prior to reaching FID. And we also intend to have a significant partnership with one or more industry participants. Additionally, we will continue to evaluate potential M&A opportunities in the petrochemical space. Turning to the Cushing South Pipeline, in June 2021, we commenced service on the 65,000 barrel per day crude oil pipeline providing transportation service from our Cushing Terminal to our Nederland Terminal, which also provides access for Powder River and EJ Basin barrels to our Nederland Terminal via an upstream connection with our White Cliffs pipeline. In the first quarter of 2022, we completed Phase 2, which nearly doubled the pipeline's capacity to 120,000 barrels per day. The majority of the capacity is under take-or-pay contracts and the pipeline is already utilized in both Phase 1 and Phase 2 capacity to move volumes south to our Gulf Coast terminals, providing significant revenue potential as the arbs improve. Next, in April, we placed into service the Ted Collins Link, which provides market connectivity for our Houston terminal. The Ted Collins Link gives 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 ability to provide a neat Bakken barrel to markets along the Gulf Coast. In April, we completed our inaugural shipment of oil from our Houston terminal for export utilizing this system and expect our export volumes to grow throughout the year. Our Permian Bridge project, connecting our gathering and processing assets in the Delaware and the Midland Basin, were placed into service in October of 2021. In addition, in the first quarter of 2022, we completed an expansion of Permian Bridge, which brought the pipeline's total capacity to over 200,000 Mcf per day. This project allows us to move rich gas out of the Midland Basin to utilize available Delaware processing capacity more efficiently, while also providing access to additional takeaway options. It is being utilized to provide operational flexibility between our processing facilities in the 2 basins. Current Permian Basin plant inlet processing volumes are over 2.2 Bcf per day and we're evaluating our options to meet increasing production from the basin. Construction of our new 200 million cubic foot per day GrayWolf processing plant in the Delaware Basin has commenced. The GrayWolf plant is supported by new commitments and growth from existing customer contracts and is expected to be in service by the end of this year. In addition to providing 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 additional revenue streams for our intrastate and NGL segments. And due to significant producer demand, we anticipate moving forward with a second processing plant in the Permian Basin for which we are currently determining the best location. The plan has already included in our 2022 growth capital forecast. We continue to be very excited about our pipeline project from the Permian Basin to address the growing needs for additional natural gas takeaway. This project has significant advantages over competing projects. It would include the construction of a new intrastate pipeline from the Midland Basin to our extensive pipeline network south of the DFW area, paralleling existing right-of-way. From there, our vast pipeline systems provide significant flexibility to deliver natural gas to premier markets along the Texas Gulf Coast, including Katy, Beaumont and the Houston Ship Channel as well as to Carthage with potential deliveries to most major U.S. trading hubs and markets. Given the strong interest we are seeing for this project and ongoing producer discussions, we hope to announce additional information soon. In the meantime, we are working on time-sensitive surveys and the regulatory process has already begun. This project is an ideal solution for natural gas growth out of the Permian Basin and is clearly the best choice for customers in regard to timing, cost, flexibility and the access to multiple premium and liquid markets. Given the proposed route and our ability to utilize existing assets, we believe we could complete construction of the project in 2 years or less once we have reached FID. In the meantime, modernization and demodded acting work on our Oasis pipeline continues, which will add an incremental 60,000 Mcf per day of much-needed capacity out of the Permian Basin. This capacity is expected to be available by the end of 2022. Next, construction on the Gulf Run Pipeline, which is a 42-inch interstate natural gas pipeline with 1.65 Bcf of capacity is underway. Gulf Run is backed by a 20-year commitment for 1.1 Bcf per day 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 United States with the LNG export market. Pipeline construction is underway and is expected to be completed by the end of 2022. As demand continues to grow out of the Haynesville, we expect to move forward with an expansion project in the not-too-distant future. Turning to our Trans-Panama Gateway pipeline. We are working closely with the appropriate entities within Panama to successfully bring this project to fruition. Panama's geographic location and favorable investment climate make this an attractive project. We remain optimistic about the Trans-Panama Gateway pipeline and the significant value it will bring to markets around the world. Now for an update on our alternative energy activities. We continue to pursue a number of projects related to carbon capture, including sequestration, enhanced oil recovery and utilization projects. We are in active discussions with several developers who have applied for Class 6 sequestration permits with the EPA in Louisiana in close proximity to our facilities that would be good candidates for carbon capture and sequestration. Unfortunately, the approval process for these sequestration permits generally takes 2 to 3 years to obtain. However, in addition to our desire to lower our carbon footprint, we remain focused on our primary business, which is providing the essential energy infrastructure necessary to grow domestic energy production which is vital to ensuring our country's energy security and the growing needs worldwide, providing additional supplies of clean, affordable and reliable natural gas and vital natural gas liquids is the most logical and quickest way to reduce emissions, while also significantly improving the quality of life for billions of people in developing nations around the world. With the significant growth in our natural gas transportation and natural gas liquids segments, along with our extensive export capabilities through our NGL terminals and with line of sight to reach FID for our Lake Charles LNG project, we expect to continue to play an important role in reducing emissions while improving living conditions throughout the world. Now let's take a closer look at our first quarter results. Consolidated adjusted EBITDA was $3.3 billion compared to $5 billion for the first quarter of 2021. Results for the first quarter of 2021 included a contribution of approximately $2.4 billion from Winter Storm Uri. Excluding this contribution, first quarter 2022 adjusted EBITDA would have been up approximately 25% over the first quarter of 2021. DCF attributable to the partners as adjusted was $2.1 billion for the first quarter of 2022 compared to $3.9 billion for the first quarter of 2021, again, as a result of the impact to the prior period from Winter Storm Uri. For the first quarter, we saw higher transportation volumes across all of our segments as well as a full quarter contribution from the available assets that were acquired in December 2021. On April 26, we announced a quarterly cash distribution of $0.20 per common unit or $0.80 on an annualized basis. This distribution will be paid on May 19 to unitholders of record as of the close of business on May 9. This distribution represents a 30% increase over the first quarter of 2021 and represents another step in our plan to return additional value to unitholders, while maintaining our leverage ratio target of 4 times to 4.5 times debt-to-EBITDA. Now turning to results by segment, starting with NGL and refined products, adjusted EBITDA was $700 million compared to $647 million for the same period last year. This was primarily due to higher fractionation and refinery services margins, higher terminal services margins related to increased throughput at our Nederland Terminal in the first quarter of 2022, as well as an increase in our Northeast blending and optimization activities. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 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 and higher volumes from the Permian and Eagle Ford regions. And our average fractionated volumes were 804,000 barrels per day compared to 726,000 barrels per day for the first quarter of 2021. We recently tied our 1-day maximum throughput record through the fracs at over 960,000 barrels. And for the month of April, we reached an all-time monthly throughput record averaging well over 900,000 barrels per day. For our crude oil segment, adjusted EBITDA was $593 million compared to $510 million for the same period last year. This was primarily due to higher transportation volumes on our Texas crude pipelines, improved performance on our Bakken and Bayou Bridge pipelines, increased throughput at our Gulf Coast terminals as well as the addition of the Enable assets in December of 2021. Crude oil transportation volumes increased to 4.2 million barrels per day compared to 3.5 million barrels per day for the same period last year, driven by higher crude oil prices, higher refinery demand and Winter Storm Uri impacting crude oil production in the prior period. For our midstream, adjusted EBITDA was $807 million compared to $288 million for the first quarter of 2021. This was primarily due to the acquisition of the Enable assets in December of 2021 and an increase related to favorable NGL and natural gas prices as well as increased production in the Permian and South Texas regions. In addition, the first quarter of 2021 included a negative impact related to Winter Storm Uri that did not occur in the first quarter of 2022. Gathered gas volumes were 17.3 million MMBtus per day compared to 12 million MMBtus per day for the same period last year due to the addition of the Enable assets, increased production in South Texas as well as additional gathering capacity from the Permian Bridge pipeline in West Texas. Permian Basin volumes continue to be strong and Midland inlet volumes remain at or near record highs. We are utilizing the Permian Bridge daily to optimize our available processing capacity as well as increasing our processing capacity in the area to accommodate incremental demand we are seeing. In our interstate segment, adjusted EBITDA was $453 million compared to $453 million for the first quarter of 2021. During the quarter, we benefited from the addition of the Enable assets as well as the volume growth on our Transwestern Rover and Trunkline systems as a result of increased rates and higher utilization due to more favorable market conditions and volume growth in the Haynesville Shale. While volumes have continued to improve, this growth was partially offset by a decrease due to gains recorded in the first quarter of 2021 related to Winter Storm Uri operational gas sales. In addition, adjusted EBITDA was impacted by contract expirations and a shipper bankruptcy on our Tiger pipeline. More recently, we have seen steady growth in the interstate segment with Transwestern continuing to benefit from high prices and demand for gas delivery out west, and Trunkline and Tiger both seeing strong demand related to increased activity on the Gulf Coast and in the Haynesville Shale. In fact, we are currently seeing record volumes from Tiger. And for our interstate segment, adjusted EBITDA was $444 million compared to $2.8 million for the first quarter of last year. The change was primarily due to the absence of higher earnings from Winter Storm Uri in the first quarter of 2021, which was partially offset by the addition of the Enable assets in December of 2021. Since the end of the first quarter, we have seen heavy utilization on our HBL system due to increased demand for gas takeaway out of the Permian as well as strong volumes in South Texas. In addition, due to increased activity in the Haynesville Shale, our Rick pipeline system is currently flowing at or near capacity. We expect this demand to continue through the rest of 2022. Now turning to our 2022 adjusted EBITDA guidance, given our strong performance in the first quarter as well as continued increasing demand for our products as we move through the rest of the year, we now expect our adjusted EBITDA to be between $12.2 billion to $12.6 billion. This is up compared to our previous guidance of $11.8 billion to $12.2 billion. And moving to our growth capital update for the 3 months ended March 31, 2022, Energy Transfer spent approximately $390 million on organic growth projects, primarily in the midstream, interstate and NGL and refined products segment, excluding Sun and USA compression CapEx. For the full year 2022, we now expect growth capital expenditures, including expenditures related to the recently acquired Enable assets to be between $1.8 billion to $2.1 billion compared to our previous forecast of $1.6 billion to $1.9 billion. Our revised growth capital reflects the addition of spend associated with our new Permian gas takeaway pipeline. Now looking briefly at our liquidity position as of March 31, 2022. Total available liquidity under our revolving credit facilities was approximately $2 billion, and our leverage ratio was 3.55x for the credit facility. We continue to have strong support from our banking partners, and in April 2022, we amended our $5 billion revolving credit facility to extend the maturity to April 2027, with substantially the same terms and pricing. We continue to expect to generate a significant amount of cash flows in 2022, which will be strategically allocated in a manner that best positions us to continue to improve our leverage, invest in high-returning growth projects and return value to our unitholders. And we expect to continue to pay down debt throughout the year with excess cash flow from operations. During the first quarter, we saw strong performance from all of our segments with significant volume growth supported by improved production and increased demand that we expect to continue throughout 2022. We have already seen further improvements in production, market conditions and domestic and international demand for our products since the end of the first quarter, and we remain bullish about the future of our industry and the need for natural gas and natural gas liquids. As we look for additional ways to address existing and new demand for our products, we will continue to evaluate and pursue strategic growth projects that enhance our existing asset base and generate attractive returns like our Permian gas pipeline project. And we will also look 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.

I just have a couple of questions about Lake Charles. Exciting that you're targeting FID in the fourth quarter of 2022, can you just kind of walk us through besides getting contracts, the other things that would need to happen for that? I think there was an engineering review going on. I think you need a FERC extension, getting a partner, but all of the stuff around reaching FID.

Yes. This is Tom Mason, I'm in charge of our LNG project, and we're really excited about where we are today. We've got really strong demand from really high-quality customers. We're really confident about reaching FID. Of course, the marketing and the offtake agreements is key to getting a deal done. The other things that you mentioned are underway that the update on the EPC bid process, bid refresh is underway. We filed an application for an extension of our construction deadline with the FERC. We understand that's in process, and we're confident that we'll receive approval of that in the near future. So I think things are going well, and we're really excited about it.

Okay. So you see the contracting as sort of the time-critical path, I guess?

Yes. The situation in Ukraine has significantly affected demand, and we are making good progress on the contracts, which are the critical factor for getting a deal done.

This is Mackie. Let me add just one thing, if I could, Jean, sorry about that. I was listening to Tom Long and listened to Tom Mason and they're pretty even-keeled laid back. And I don't think they're excited but they don't really show how excited we are in this LNG project has really taken off. It's sad it took a travesty like what's going on in Ukraine to wake up the world. It certainly has woken up Europe and Asia and China. Hopefully, they'll wake up some of our administrators, but Tom has done a fantastic job, and we've got an enormous amount of interest, as you can imagine, and we are shocked if we don't get to FID by the end of this year and look forward not only to get that project down the road and signed, but also look forward to all the upstream pipeline transportation business will come with that project.

Well, that's a lot of excitement. I'm also excited. And then just as a follow-up to that, can you kind of comment on whether you're actually seeing European utilities sign contracts? It seems like there's been a lot of contracts recently, but not really from them. Do you see that as going through the marketers? Or just any commentary that you can provide on that would be helpful.

Well, it's an interesting question because the utilities are kind of struggling with trying to satisfy their immediate and near-term demand for gas, as you could imagine. But for long-term contracts, they're still interested. I think there's been kind of some issues with financial matters based on the high price of demand for natural gas currently. And so there could end up being some government guarantees for some of the longer-term offtake contracts, so we're certainly in contact with them. But you're right, there's kind of been a lack of real commitments for long-term contracts at this point.

I just want to start off with the EBITDA guide uplift here. I want to dive in a little bit for what's happening in 2022 here. If you could break down the drivers, being it better-than-expected volumes? Or is it better-than-expected price that's the driver here? And if I look at the first quarter results, and I annualize that, granted, there's some seasonality in the business, so it would kind of point to over the high end of the new range. So just wondering what some of the puts and takes could be there?

This is Tom Long. I'm excited about the first quarter results, particularly from our optimization team. As we review our assets, you'll notice the intrastate segment's performance. Looking ahead for the rest of the year, we've adopted a cautious approach to pricing, which has played a significant role in our revised guidance. While the first quarter shows a substantial increase, representing the revised guidance level, the results could range from approximately $225 million to $250 million, which could be categorized as one-time, yet not nonrecurring. Our outstanding team and asset base will continue to emphasize optimization in our results.

I'm curious about the increase in CapEx. Is it solely due to the Permian gas project, or are there other projects contributing to this CapEx raise? Additionally, is the estimate for 2023 also increasing? Any insights on the timeline for CapEx would be appreciated.

Yes. This is Mackie again, Jeremy. We have many moving parts in our partnership. As you know, we are constructing GreyWolf and have decided to build another plant, and we are determining its location. We have numerous gathering opportunities. Most of our large, multi-billion-dollar projects are already developed, and as we move into this year and the coming years, we will be able to generate significant volume and revenue from the assets we have completed. However, we do have GreyWolf and parts of the other projects we plan to expand in the near future.

As a follow-up to CapEx and looking ahead to 2023, we've noticed some recent tractive capacity added by competitors. Your comments about achieving record frac volumes caught my attention. I'm curious about how your team is approaching frac A at this stage, considering it is about halfway complete and might have some remaining CapEx needs to finish the project.

Yes, Brian, that's a great question. Currently, we are transporting more volumes from the Permian and the Eagle Ford than we ever have before with NGLs. We need to make a decision on this soon. We're operating at full capacity right now at about 960, but we won't proceed until we secure long-term commitments for that net frac. We expect that could happen in the next quarter or sooner. As always, we will be cautious with our capital and will allocate it as necessary, but we do plan to make that decision in the near future.

So just to clarify that could just be upside to '22 CapEx? Or is that mostly 23?

It'd be mostly in '23.

And then as my follow-up, a lot of progress on the LNG front with the recent flurry of contracts. Just kind of curious if you could provide some thought process around the ultimate ownership structure and potentially bringing in partners, whether that's a financing partner or a strategic partner, just given the ultimate interest in LNG and ultimately, how that would fit in the ultimate Energy Transfer portfolio?

Yes, this is Tom Mason. As we previously announced, we plan to sell a portion of our equity primarily to infrastructure funds. There is a significant amount of capital seeking high-quality, long-term cash flow from a project like this, so we believe it will be a great way to finance it. We aim to retain at least 25% of the project, although we have not made final decisions on that yet. There is considerable interest in the equity aspect of this project.

Just sticking on Lake Charles. I guess if you didn't move ahead with the project, can you quantify how much of a gas demand pull this could have on your existing pipes? I guess it would be Trunkline and Gulf Run that feeds into it. How much spare capacity do you have on trunk line? Would you have to expand either Trunkline or Gulf Run because of Lake Charles?

Yes, we are definitely looking to expand Trunkline and Gulf Run, as discussed earlier, and we will also continue our efforts on the West Texas project, which we expect will contribute to this as well. The advantage of our pipeline network, both intra and interstate, is that we can aggregate significant volumes from various basins and deliver them to key locations like Henry Hub and Lake Charles. We mentioned earlier that we anticipate launching an open season for Gulf Run in the latter part of May, and we expect considerable interest. Ultimately, we anticipate transporting between 2.5 to 2.7 Bcf a day into Lake Charles and additional markets in that region through our pipeline network.

And then I think you noted Haynesville production has really started to pick up the last few months. Are you seeing any interest for long-term contracts on your pipes in the region? And I guess, specifically, I'm asking about Tiger. Is there a path to maybe contract this pipe up? Or is it more kind of interruptible volumes that are flowing on it right now?

We are now nearly at full capacity, which changes on a month-to-month basis. Recently, we secured a new producer who will reach a capacity of 550,000 a day, utilizing Tiger capacity, Gulf Run capacity, and our intrastate pipeline network in Carthage. We adjust to the needs of the producers based on their requirements for the Gulf Coast. Currently, our challenge is to seek more capacity. Haynesville is growing rapidly, and we will continue to play a critical role in facilitating the transport of resources from that area through Gulf Run and our other intrastate pipelines.

A few cleanup questions on Lake Charles, if we could. Just a multipart question here, but just curious how you guys are thinking about expected project returns? And maybe what sort of CapEx we could think about going forward? Is this a pretty typical midstream return, maybe 6 to 8 multiple? Or can you do better than that? And then as you think about getting to FID, is there a level of capacity you're trying to contract first? What does that look like? And then finally, some that you're talking to several partners here on this, ultimately, how much of this project are you kind of willing to sell down? Is there a target number in mind?

This is Mackie. Tom may add to this, but we are exploring multiple capital projects and need to approach them carefully. We will ensure that we meet our established thresholds. A significant portion of the revenue we expect from the LNG project will come from the pipeline infrastructure that transports natural gas to the facility. Ultimately, we would be fine with a minimum threshold of 25%. We will manage the operations and bring in the necessary volume, and we will be satisfied with that level. Regarding the capacity needed to reach a final investment decision, we currently have interest that exceeds our capacity for 15 million tonnes, so we are very optimistic about fully contracting this. We will make informed business decisions as we get closer to the end of the year and finalize contracts, but we are confident that we will have everything contracted by then.

This is Tom Long. You've clearly mentioned that we have a lot of promising projects, which is true. However, we have not reached a final investment decision on any of them yet. Therefore, the $500 million to $700 million guidance we provided for 2023 is something we are likely not ready to commit to at this moment. As the year progresses and as these projects receive approval, we will likely provide an update. For now, we don’t have any further updates apart from the details on these projects as we aim to reach a final investment decision.

I have two questions that are somewhat unrelated. First, regarding the Northeast, how are you considering the recent launch of Mariner East? I understand that it's nearing completion and that this has been a lengthy process. What are your thoughts on the potential for future expansions, including the possibility of further developing the system from West to East, and how do you see opportunities for expanding Marcus Hook?

Mike, this is Mackie. Gosh, we are so happy to be at the end of the road on Mariner after all these years. We've built an incredible north there of 3 different pipelines that can move a variety of products. We have enormous capability by just adding pumps to significantly increase the throughput on that. It's really where additional costs will come in for any storage or chilling type assets that we'll have to build at Marcus Hook. As we alluded to earlier on this call, we have sufficient volumes for another ethane expansion at Marcus Hook. We're not sure if that's best suited or if it's better to expand at Nederland next, we'll be making that decision over the coming weeks, but we certainly expect over the next year or 2 to be expanding Marcus Hook in a big way. As I said, we built quite a franchise with a lot of money, a lot of time, a lot of effort and a lot of stress. We're past all that. We've got an enormous amount of customers around the globe. We're talking to as many as 600,000 barrels a day of NGL markets out there. So there's plenty of markets out there. And so our job from a commercial standpoint is to go secure more commitments, which we have done, and we'll be moving forward on expanding Marcus Hook and Nederland over the next several years.

Yes, Mike, we're still pretty early in this process. We couldn't be, like a lot of this, more excited about the relationships that we built down there and the operating for that. It's premature to begin talking about capital or even the exact routes for a number of reasons. We're going through a process that's required in that country. But we're very excited. We think, at the end of the day, this could be a very significant international hub for the world, not just for the Caribbean or the Western Coast of North and South America, but also, of course, for Asia. So it's a little bit preliminary to get any major details, but we remain very excited about that.

I wanted to start on the distribution. So you've now had 2 quarters where you raised it pretty quickly and pretty steadily. What factors are going to govern sort of the pace of increases going forward? And if the balance sheet is on track, I mean the business is doing very well. Is there any reason to think it won't be more of the same of what we've seen in the past 2 quarters until you get back to that $1.22 goal?

Yes, Keith, you've raised one of the most frequently asked questions right now. We really want to avoid speaking ahead of the board. We've mentioned that we'll assess this on a quarterly basis. The year has started off strong with our first-quarter results. So, let's go through each quarter and discuss this with our Board as we progress. There are other factors to consider when discussing our capital allocation, including the various significant projects we are currently working on. We will also continue to monitor our leverage metrics. I want to emphasize that we have made significant progress toward our target of 4 to 4.5. Each agency evaluates that a bit differently, so I suggest reaching out to them for their current assessments. We are getting closer to the 4.5 target, and we will take all of these factors into account quarter by quarter as we advance through the year, which will inform our decisions each quarter.

I have more information on Lake Charles. First, I want to confirm that it appears to be three trains. Mackie mentioned 2.5 Bcf a day and a capacity of 15 Mcba, so it seems you're considering three trains. Also, if you reduced your stake in the project to just a 25% ownership interest, given the economics, would your equity investment in the export facility be a very small amount?

Yes, this is Tom Mason. We would expect to have some promoted interest from the equity side. Our capital requirements would be relatively small and spread over a four-year period. Therefore, the returns can be quite good with minimal capital being deployed.

Yes, correct.

So just jumping back to the base business. Tom, you mentioned the optimization earnings and interest rate. I think when we look at the Waha to Katy spread, it was actually relatively flat quarter-on-quarter, but you all still saw a pretty significant step up there. So just wondering if you can update us on what the dynamics were that drove that optimization opportunity.

Yes, this is Mackie. There's a number of things, and we've said it before. It happened during Uri. We have such an extensive pipeline system throughout Texas. We have an incredible amount of storage strategically placed well in the Houston area and also in the DFW area. We're connected to the vast majority of the power plants either directly or indirectly and will connect to every major LDC in Texas. And so any time there's any kind of volatility or price movements, we're really able to capture that as well as spreads from day to day. There were times in that quarter where the spreads were higher from going from East Texas to West Texas, there was a period of days where the basis spread was, gosh, I think $1 higher for at least a day-or-so higher in Waha and Katy. So it's just our optimization team optimizing our assets and our pipelines and our storage at every opportunity that we have. And with the assets we have, those opportunities arise quite often in really cold weather times, high demand and also high heat days.

We have projected a total of $75 million for this year. At the moment, we don't have a specific figure for the first quarter. However, we remain confident in achieving that $75 million target for the year. Additionally, we are optimistic about reaching a $100 million annual run rate in the future. It's important to mention that we have made significant progress in integrating all results, which have exceeded our initial projections during the merger and the preparation of the S1. We are very enthusiastic about this transaction, and it is proving to be a successful venture for us.

I would like to ask about the proposed petchem cracker project. I'm curious if it would exceed your cost of capital. Specifically, I want to know how this project might integrate with some of your other assets, such as NGL pipelines, or if you are looking for commitments further upstream, or if you consider it to be a stand-alone project.

Gabe, this is Mackie. No, it won't be a stand-alone project. Like all our business endeavors, we seek synergistic benefits and revenue, both upstream and downstream. The project we're focusing on, which is gaining momentum with many high-quality customers, is expected to give us access to what we think will be inexpensive gasoline components in a year when gasoline demand may start to level off. We believe some of the feedstock for the cracker we're designing will be very beneficial. Additionally, our recent acquisition of the Spindletop asset and our plans to connect Louisiana and Houston with an ethylene and propylene system will enhance this project. This petrochemical venture will also have access to our pipeline and storage network, as well as our export business for international deliveries. So yes, we're pursuing a project similar to LNG, where we would likely have a minority stake with promoted partners, ensuring it is fully contracted with significant upstream and downstream revenue.

I guess one question, I guess, related on the pet chem side. You talked about M&A opportunities in the pet chem space. So I don't know if you could talk about what part of the petchem value chain that you're targeting specifically here on the M&A side? And whether you're kind of looking to build scale in the petchem space? Or are you looking for maybe minority ownership so you can work closer with a petchem partner?

This is Tom Long. I'll take off and then Mackie may add a little bit more. But we have been evaluating various acquisition opportunities. We still feel like that's a good way to enter it. But at the same time, we've got a very good team and we're quite comfortable with starting with a greenfield type project. So we're going to continue to look at those. And yes, it could be a partial joint venture, if you will. We're quite open to that in order to be able to step into the skill set that it takes to move into this or it could be a total acquisition. So we're looking at basically all the above as we evaluate this, including a greenfield build. Yes, that's the Kelsey disclaimer. A quick follow-up on Lake Charles. Regarding the contracts for Lake Charles, are they solely tolling fees, or do they also offer some commodity upside exposure?

They are essentially a liquefaction charge, but similar to most contracts on the Gulf Coast, they are linked to Henry Hub plus a certain percentage. Therefore, with higher natural gas prices, there is potential for increased cash flows from that.

Yes. And this is Mackie, I'll add 1 thing to that. We intend to contract out about 15 million tonnes. But as you know, that's nameplate, and there's fairly significant volume above that, that we'll be able to take advantage of as time goes on when we see a blowout in prices between the U.S. and Europe and Asia.

All right. Well, thank all of you for joining us today, and we look forward to any follow-up questions you might have.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for joining. You may now disconnect.