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spk12: Greetings. Welcome to the Energy Transfer First Quarter Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If an owner should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to your host, Tom Long. Mr. Long, you may begin.
spk11: Thank you, Operator, and good afternoon, everyone, and welcome to the Energy Transfer First Quarter 2021 Earnings Call. And thank you for joining us today. I'm also joined today by Mackie McCree and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully you saw our 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 Security 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 31st, 2021, which we expect to be filed tomorrow. I'll also refer to adjusted EBITDA distributable cash flow, or DCF, and distribution coverage ratio, all of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. I'd like to start today by looking at some of our first quarter highlights. We generated adjusted EBITDA of $5.04 billion, and DCF, attributable to the partners of ET, as adjusted, of $3.91 billion. Our excess cash flow after distributions was approximately $3.5 billion. On an incurred basis, we had excess DCF of approximately $3.14 billion after distributions of $412 million and growth capital of approximately $360 million. The increased results were primarily due to one-time impacts from winter storm URI in February, largely driven by our significant ability to transport large volumes of natural gas from our storage facilities and from market hubs in Texas to power plants, cities, and to LDCs throughout the state. Taking a closer look at the performance of our assets during winter storm URI, as the winter storm approached, we had ample advanced warning which allowed us to pre-position employees and prepare our assets for this historic winter storm. And throughout the storm, our Texas pipelines, processing plants, and compressor stations performed extremely well. Our extensive experience in operating pipelines combined with a significant amount of both long and short-term preparation allowed us to continue operating reliably throughout the storm. As part of our standard design process, we have spent a significant amount of time and effort determining which components and systems are particularly susceptible to extreme weather conditions or process disruption. In the event of severe cold temperatures, we have taken various measures to winterize these components. Our long-term preparation has included the installation of heat tracing on our pipeline systems and at our processing plants to keep piping and internal fluids above freezing point. We also know that it takes considerable investments to maintain one of the largest systems in the industry. And over the past three years, we have spent approximately $1.5 billion for maintenance related to our assets with approximately half of that spent on our Texas assets. Going back to 2014, We have been investing in and developing a dry gas fuel system in West Texas, which provides a reliable fuel source to our compressors while preventing freezing. In the days leading up to the storm, we injected additional natural gas into our pipelines as line pack prior to the storm that not only served as additional storage, but also allowed us to place natural gas volumes as close to our customers as possible. And we brought in specialized equipment that was strategically allocated across our systems to help prevent freezing, including hot starts for engines, steam trucks, steam generators, and methanol injection units. Our employees, including operations personnel and mechanics, were deployed to key assets and to those facilities at greatest risk during freezing operating conditions. This included more than 25 facilities on our pipelines and more than 25 processing plants across Texas. These key facilities were manned 24 hours a day from February 13th through the 18th, which resulted in approximately 50,000 hours of overtime worked by our employees. This pre-deployment preparation allowed us to resolve and prevent most operational issues once the storm arrived. To manage through the storm, we did everything within our control to keep our plants running and circulating fluids and field compression idling so that we were prepared to deliver gas to customers as soon as volumes returned to our facilities. We utilized our Texas storage facilities where we have 63 BCF of working storage capacity. Withdrawals from these facilities reached a peak rate of approximately 1.7 BCF during the storm. Additionally, we did everything we could to purchase and or transport natural gas from other areas including bringing gas in from out of state for delivery to our customers. We conserved power everywhere we could, including facilities like Mont Bellevue, where we reduced power by shutting down our fractionators, and we also switched from electric to gas on our dual-drive compressor units, leaving in excess of approximately 200 megawatts per hour on the grid. This storm highlighted and emphasized the importance of having reliable, flexible assets and an experienced operations team. I've said it before, but we truly believe our operations team is second to none, and their efforts during the winter storm Uri were extraordinary. In a year where we celebrate our 25th anniversary, we had a history of reliable service through multiple extreme adverse weather events, and our performance this time was no exception. Not a surprise here, but we now have opportunities to lock in longer-term contracts for storage and firm transportation capacity. Switching gears to an update on the acquisition of Enable Midstream Partners, which we expect will provide increased scale in the MidCon and Arklatex regions and improve connectivity for our natural gas and NGL transportation businesses. On April 7th, the SEC declared the registration statement on Form S-4 effective. And on April 12th, the two largest Enable unit holders, CenterPoint and OG&E, delivered written consents to approve the merger, which is sufficient to approve the transaction. The transaction is subject to HSR and other customary closing conditions. The combination of energy transfers and Enable's complementary assets will allow the new, larger company to provide superior, flexible, and competitive service to our customers as we pursue additional commercial opportunities. The combined company also expects to achieve significant cost savings while enhancing our ability to serve customers. Integration teams from both companies are currently engaged in the integration planning process, and we continue to expect the combined company to generate more than $100 million of annual run rate cost synergies before factoring in potential financial and commercial synergies. I will now walk through recent developments on our major growth projects, starting with Dakota Access. On May 3rd, the Army Corps filed a status report informing the court that it has not changed its position related to the continued operations of the pipeline. The Army Corps also advised the court that it expects the environmental impact statement to be completed by March of 2022. We continue to cooperate with the Army Corps related to their preparation of the EIS process. Dakota Access is a world-class asset, and we expect it to continue flowing oil reliably, safely, and efficiently as it has done for the past four years. Dakota Access is critical to this country for jobs, tax revenue, and for energy security and independence. Next, construction on the Ted Collins Link is progressing, and we expect it to be in service early in the fourth quarter of 2021. This project will ultimately allow us to transport up to 300,000 barrels per day of crude oil from West Texas and Nederland to our Houston terminal upon full completion. In April, we announced that we will post a joint tariff for Crude Oil Transportation Service to move ET and third-party Powder River and DJ Basin barrels through our Cushing and White Cliffs pipeline to our Nederland terminal. Joint tariff service is expected to commence by June 1st of this year. Upon completion of the first phase, we will be able to transport approximately 65,000 barrels per day of crude oil from the DJ Basin and Cushing area to Nederland, expandable to 120,000 barrels per day. Now turning to our Mariner East system, first quarter of 2021, NGL volumes through the Mariner East pipeline system increased more than 20% over the first quarter of 2020, and we are experiencing very strong demand on Mariner East for April and May. On April 1st, we began transporting natural gasoline through Mariner East to our Marcus Hook terminal for gasoline blending and local consumption. We also recently completed the final drill necessary to commission our Pennsylvania Access Project, which will allow refined products to flow from the Midwest supply regions into Pennsylvania, New York, and other markets in the Northeast. We continue to expect the next significant phase of the Mariner East projects to be in service in the second quarter of 2021. And the final phase of Mariner East pipeline is expected to be completed in the third quarter of 2021. Our Mariner East pipeline system and Marcus Hook terminal provide the most efficient transportation route for liquids in the Northeast providing customers the optimal way to reach the highest price markets for their products. Now for a brief update on our recently completed projects at our Nederland terminal. We have completed the expansions of our LPG facilities along with construction of a new 20-inch pipeline that directly links our fractionation and storage assets at Mont Bellevue to our Nederland export terminal in the fourth quarter of 2020. Volumes on these assets began ramping up in the first quarter of this year, and we expect them to continue to increase throughout the year. We are now capable of loading nearly 500,000 barrels per day of LPGs at our Needland terminal, which we expect to consistently remain above 80% utilized year-round. And on our 180,000 barrels per day ethane export joint venture with Satellite Petrochemical, We have now loaded three VLECs under this joint venture, each with over 900,000 barrels of ethane, and we have loaded three additional ships with ethane out of our Nederland terminal, bringing our total ethane loaded out of this facility to nearly three and a half million barrels through April. Our NGL franchise at Nederland and Mont Bellevue now have four pipeline systems capable of moving large volumes of ethane propane, butane, and natural gasoline from our fractionators and our storage facilities at Mont Bellevue to our Needland Terminal. As a reminder, with the completion of our LPG and orbit expansions at our Needland Terminal, as well as expansions completed at our Marcus Hook Terminal in Northeast at the end of 2020, our total NGL export capacity is now just over 1 million barrels per day, which supports the strong international demand for NGL exports from the U.S. Lastly, we are pleased to announce that we are moving forward with our Permian Bridge project, which will connect our gathering and processing assets in the Delaware Basin with our GMP assets in the Midland Basin. For this project, we will convert approximately 55 miles of an existing 24-inch NGL pipeline into rich gas service and utilize it to tie our Midland and Delaware Basin assets together. This will allow us to move approximately 115,000 MCF per day of rich gas out of the Midland Basin and operate existing capacity more efficiently, while providing access to additional takeaway options. This project is included in our revised 2021 growth capital guidance and saves us significant capital by being able to fully load our entire Permian Basin processing assets before we commit to building another cryogenic processing plant. This conversion is expected to be completed in the fourth quarter of 2021. Now for a quick update on our alternative energy activities in February, we announced that we have created an alternative energy group to focus on renewable energy projects such as solar and wind farms, either as a power purchaser or in partnership with third party developers. And we'll also look to develop renewable diesel and renewable natural gas opportunities. We have significantly ramped up our export of propane and ethane for power generation that in many cases displaced diesel and other fuels that cause greater CO2 emissions. We recently saw the startup of the Maplewood II solar project, and we are utilizing power from this solar farm to help run our assets in West Texas, including three cryogenic plants in the region, as well as numerous compressor and pump stations. We are in advanced discussions to support a significantly larger solar project with a long-term power purchase agreement that we anticipate announcing in the next few weeks. We are also in discussions with our solar developers regarding the utilization of some of our existing acreage in the Northeast. We continue to pursue several carbon capture and sequestration projects related to our gathering and processing facilities in Texas. that we believe will generate attractive returns through structures that would provide third parties with the benefit of federal tax credits and provide us with annual cash flows with very low capital requirements. Our engineering and commercial teams are currently developing a carbon capture project related to our markets of terminal that would involve carbon utilization for commercial application and based upon preliminary cost estimates and customer feedback, This project looks feasible without the benefit of federal tax credits. We are also reviewing our ESG profile as reported by external ESG rating groups, and we are working to improve our profile scoring, partially resulting from improved communications to address various inaccuracies and misrepresentations. And we are also expanding our ESG metrics reporting through industry-recognized reporting templates. Now let's take a little closer look at our first quarter results. Consolidated adjusted EBITDA was $5.04 billion compared to $2.64 billion for the first quarter of 2020. DCF attributable to the partners as adjusted was $3.91 billion for the first quarter compared to $1.42 billion for the first quarter of 2020. The increased results were primarily driven by our ability to transport natural gas from our storage facilities and market hubs in Texas to power plant cities and to LDCs throughout the state during the historic freezing conditions. On April 22nd, we announced a quarterly cash distribution of 15.25 cents per common unit or 61 cents on an annualized basis. This distribution will be paid on May 19th to unit holders of record as of the close of business on May 11th. Turning to our results by segment, starting with our intrastate segment, adjusted EBITDA was $2.8 billion compared to $240 million in the first quarter of last year. This increase of approximately $2.6 billion was primarily due to the higher natural gas storage withdrawals related to winter storm URI. For 2021, as I already mentioned, we are now seeing new opportunities as producers look to lock in firm transportation and storage. For NGL and refined products, adjusted EBITDA was $647 million compared to $663 million for the same period last year. This was primarily due to a $37 million impact related to lower producer volumes from West Texas on our Texas NGL pipelines and feeding our Mont Bellevue fractionators during the storm URI, as well as COVID-19 related volume reductions. These decreases were partially offset by higher margins from our Mariner East system and Needle and Terminal. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.5 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 volumes on our Mariner East pipeline system, as well as increased export volumes feeding into our Needle and Terminal from the initiation of service on our propane and ethane export projects. On our fractionators, average fractionated volumes were 726,000 barrels per day compared to 804,000 barrels per day for the first quarter of 2020. Transportation and fractionation volumes have been increasing in the second quarter and are currently back to above first quarter 2020 levels. For crude oil segment, adjusted EBITDA was $510 million compared to $591 million for the same period last year. This was primarily due to lower volumes through our Texas and Bakken crude pipelines and terminals as a result of COVID-19 demand reductions, as well as lower rates along our Texas crude pipelines and a $20 million impact from winter storm URI. Since the end of the first quarter, we have seen Permian Basin crude volumes increase on our system as drilling picks up and more ducts are being completed. For midstream, adjusted EBITDA was $288 million compared to $383 million for the first quarter of 2020. This was largely the result of a $167 million impact due to winter storm Uri as well as lower volumes which were partially offset by favorable natural gas and NGL prices and reduced operating expenses. Gathered gas volumes were 12 million MMBTUs per day compared to 13.3 million MMBTUs per day for this period last year due to lower volumes in our South Texas, our MidCon and Panhandle area, Permian and North Texas regions, much of which was due to the winter storm. This was partially offset by volume growth in the Arklatex region. We are starting to see production pickup in Permian Basin Inlet volumes reaching a monthly record in April. This growth is also expected to have a positive complementary impact on our NGL segment from additional production of NGLs out of our West Texas processing plants. In our interstate segment, adjusted EBITDA was $453 million compared to $404 million for the first quarter of 2020, primarily due to an $88 million positive impact from our ability to utilize our pipelines to bring additional natural gas to the mid-continent region during the February storm, as well as reduced operating expenses. These were partially offset by contract expirations on TIGER and on FEP. For 2021, our previous full year adjusted EBITDA guidance was $10.6 billion to $11 billion, which we announced during the week of winter storm URI. These numbers included an expected impact of approximately $200 million related to the storm. Given our ability to utilize our extensive natural gas storage and transportation assets to provide a significant amount of natural gas for consumption during winter storm URI, In total, we now expect to realize approximately $2.4 billion from the storm for full year 2021, inclusive of $100 million of expenses, which may be incurred throughout 2021 related to the storm. As a result, we're updating our full year adjusted EBITDA guidance to $12.9 billion to $13.3 billion, excluding any contribution from the announced enable acquisition. This is up approximately $100 million compared to our previous adjusted EBITDA guidance, excluding the impacts of winter storm URI. Our system was designed to be reliable and flexible, even under adverse operating conditions, and combined with the significant amount of preparation our team completed prior to the storm, we believe this highlights just how valuable our assets and our employees are to energy transfer. Now moving to a growth capital update. For the first quarter ended March 31st, 2021, energy transfer spent $360 million on organic growth projects, primarily in the NGL and refined product segment, excluding Sun and USAC CapEx. For full year 2021, we now expect growth capital expenditures to be approximately $1.6 billion. The increase from our previous forecast of $1.45 billion is primarily due to the addition of several small opportunistic projects, primarily in the midstream segment, as well as the acceleration of some project spend from 2022 into 2021. We continue to focus on aligning capital outlay with customer needs and remain disciplined in regards to all spending. These new projects are focused on improving optionality around our existing assets. The Permian Bridge which is a new project I discussed earlier on the call, involves converting a portion of an NGO line in the Permian into rich gas service in order to connect our Midland and Delaware Basin GMP assets together. We remain disciplined, and for 2022 and 2023, we continue to expect to spend approximately $500 to $700 million per year. Now looking briefly at our liquidity position, as of March 31, 2021, Total available liquidity under our revolving credit facility was approximately $5.08 billion, and our leverage ratio was 3.23 times per the credit facility. The additional cash flows achieved from the winter storm also allowed us to accelerate the timing of our debt reductions. During the quarter, we were able to repay approximately $3.7 billion in debt with cash flow from operations, which equates to a permanent reduction to our run rate leverage of approximately a third of a turn. We continue to focus on accelerating debt reduction and achieving our leverage target of four to four and a half times on a rating agency basis. Once we have reached our leverage target, we will look to return additional capital to unit holders in the form of unit buybacks and or distribution increases, with the mix dependent upon our analysis of market conditions at the time. we remain committed to maintaining and improving our investment-grade rating. In concluding remarks, the performance of our Texas intrastate and storage assets during winter storm URI demonstrates the value of having a strong, reliable, and extensive geographical footprint, which allowed us to meet critical demand throughout the extreme adverse weather event. In addition, our employees deserve a significant amount of credit for their dedication during the extremely difficult weather conditions. Our strong first quarter results helped accelerate the pay down of debt. Capital discipline and deleveraging continue to be among our top priorities. Looking ahead, we remain excited about the acquisition of Enable, which we view as a strategic opportunity to expand our scale and midstream connectivity while remaining consistent with our goal of improving our financial position through deleveraging. Our long-term business outside of the winter storm is returning to pre-COVID levels and will be enhanced by further ramp-ups from our LPG and ethane export projects at our needle and terminal. In addition, April and May volumes are shaping up favorably. We also continue to explore development of alternative energy projects and opportunities to reduce our environmental footprint. Operator, please open the line up for our first question.
spk12: Thank you. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Please limit to one question and one follow-up question. Our first question is from Gabe Maureen with Mizuho. Please proceed with your question.
spk00: Good afternoon, everyone. Maybe I can start off, and congrats on a terrific quarter. Maybe if I can start off on the winter storm. Of the $2.4 billion you earned, how much of that, I guess at this point, is cash in the door and Dave, you can also talk about how much you might have reserved against your STRM earnings for potential litigation and maybe the time to resolve some of what's still in dispute.
spk11: Yes, Gabe. This is Tom Long. I would say of the $2.4 billion, you can say all of it is in the door. As highlighted in our prepared remarks, we paid down $3.7 billion in debt. So when you look at the cash, you can see that the collection efforts have gone very well. I will say, as far as any disputes that we may have, we feel like that we have recorded very strong numbers for the quarter, very solid numbers. And as far as reserves go, I would say the numbers stand as presented for this quarter.
spk00: Thanks, Tom. And then maybe if I can follow up on the Permian Bridge project and how you think about your overall processing capacity within the Permian, both Midland and Delaware. Does this project let you defer additional processing capacity if we're about to, you know, ramp up volumes here again? So if you could just speak to kind of how that project fits within the capacity out there.
spk08: Yeah, this is Mackie Gay. Welcome back, by the way. Thank you. We, you know, we're one of the biggest players and have been growing out there for years. I think we built 10 or 12 200,000 day cryos in, Kind of what the pandemic did, it slowed down certain areas of the Permian Basin and allowed us to kind of step back, see what our commitments were, and take a more disciplined look at spending capital, kind of the path we've been on. And as we see the volumes grow more right now in the Midland Basin, it has made more sense to not build another plant there and to bridge it over or move rich gas over to our Delaware system where we do have some capacity. However, as time goes on, we will need another cryo at some point in the future, but this gives us time to evaluate it, to watch all the volumes return, and to fully load what we've already built before we start spending more capital. So it's a great project that our team came up with. We continue to look for ways to better utilize our pipeline assets, and this is a great example of that. Great. Thanks, Mackie. Sure.
spk12: Thank you. Our next question is from Schneir Gushuni with UBS. Please proceed with your question.
spk04: Hi. Good afternoon, everyone. I was wondering if we can start off with the guidance aspect. You know, clearly the natural gas segment did obviously very well. When I sort of think about it X that, you know, the rest of the segments were obviously or a lot of the segments were impacted by the storm. yet you were able to increase your guidance or your legacy guidance by $100 million kind of on an exit storm basis. That sort of seems to suggest that you sort of expect the base business to do even better than the $100 million that you've shared with us kind of on an ongoing basis. Can you share with us the components of what's driving the improved outlook? Is it the exports that you prefaced or talked about in the preparative arts, or are there some other areas that we should be thinking about?
spk08: Yeah, this is Mackie again. I'll start and Tom can follow up. But, you know, we couldn't be more pleased with our results and what these assets did, but more importantly what our people did. But really where our excitement is is the future. And a reflection of the volumes in the first quarter aren't where we're going. If you look at and what you'll see here in the future is where the volumes are now. In April and May we're seeing significant growth. I'll give you an example. The word record falls into almost everything we're working on. I'll just walk through a few. For example, you heard earlier, we're at record volumes, all-time volumes in the Permian Basin. We've never processed more gas than we are right now. The volumes, the residue volumes coming out of the Fort Worth Basin that we move about 25% of is at all-time highs. It's about 13 to 13.1 BCF, which is right at or higher than the highest level we've ever had in the Permian Basin. Somebody reported here recently that Haines the most gas that's ever been produced out of Hainesville was produced in the month of April. And you just go on and on. If you look at Mexico, the record, we're almost to 7 BCF, about 30% of that volume moves through our assets. Our two 42-inch pipelines in West Texas are now moving 1.4 BCF a day, where they've been significantly less than that in the past. Those are much higher volumes than we expected. And it kind of goes on and on. If you look at Even on our refined product, on our terminals, we now are at higher levels than we've been since the end of 2019. Our throughput on our refined product pipelines are up about 70% from the lows of last summer. So there's a lot of aspects that go into this of why we're very bullish on not only this year, but for many years to come. And a few adders to that, it was mentioned on on the script is that the industry in the country, I think, has recognized how valuable natural gas generation is. And more importantly, how important big-inch pipe that can deliver large volumes to power plants and to cities and to LDCs and that can bring gas out of storage is really invaluable. And those assets have been way undervalued for the last, in our opinion, five, six, seven years. And that value was recognized big time in February. And so ironically a lot, coincidentally, a lot of the contracts are rolling off on our transport and our storage deals this year, even in the next month or two. And as you can imagine, the value of that service is going up. And so we'll be able to extract a fair but market value for that service, and we're excited about that. And then also we're even seeing spreads, for example, in one of our tougher segments, our crude segments. We're now seeing the prices at Nederland at 15 to 25 cent per barrel premiums above Houston, and there's reasons for that. Even St. James, which helps fill up our Bayou Bridge pipeline, there's a higher demand there. So this is a long-winded answer to your question, but the bottom line is there is so much upside that we really didn't see before this year started that we're now seeing as we've come out of this storm really across the board on all of our systems.
spk04: That was super helpful and more than I expected. Appreciate that. Maybe to continue on kind of the momentum and so forth, one of your peers noted on their conference call that the storm impact caused a lot of customers to sort of rethink their services in general. and they're seeing some more requests or inquiries around potential contracting or contracting more business and so forth. Is that something that you're seeing as well, too, and something that you would look to capitalize on?
spk08: Yeah, this is Mack again. Yes, absolutely. As I mentioned, we believe that service, our transportation service, and more importantly, our storage capacity has been undervalued for many years. So we have had many questions. There's some RFPs that have come out requesting more. We have some existing customers that have asked to double their storage capacity. They're asking for more withdrawal capability. And we're certainly working with those and would love to contract up the majority of our storage at what we believe are fair market prices. So we're pretty high on the value of those assets and look forward to some much improved margins around those.
spk04: Perfect. Thank you very much for the color today and have a great afternoon. Yeah. Thanks.
spk12: Thank you. Our next question is from Jeremy Toney with JP Morgan. Please proceed with your question.
spk10: Hi. Good afternoon. Good afternoon.
spk11: Jeremy, how are you?
spk10: Good. A lot of great commentary there, Tom. Thanks for that start off. Just wanted to pick up on carbon capture as you outlined there. A lot of thoughts there. I was just wondering if you could help me think through, I guess, what could be possible here? And I think you noted that there could be a mix of kind of third-party capital as well here. And so just wondering, is this a situation where you could kind of take existing assets, repurpose and contribute to like a JV or just trying to see, I guess, how far along these opportunities are and where you see the best place for storage here?
spk07: This is Tom Mason. You know, it's an interesting area, of course, and we're spending a lot of time looking at opportunities. In Texas, you know, with our gas processing plants, we have a fair amount of CO2 that we're evaluating how to best capture that and try to work a structure where we can get the 45Q tax credits and therefore reduce get joint venture, getting third-party money to actually pay for the capture equipment and the sequestration wells. So that's interesting that the permitting takes a while, but we're doing some studies on the viability and location for those injection wells. And so that's a tax credit play in the Northeast. We're looking at Marcus Hook as a potential way of monetizing the CO2, capturing it, but using it for industrial CO2 applications. And so that would not rely on the credits. And we're working through some feasibility studies on that. So we're spending a lot of time on it. It looks like some real attractive opportunities to capture carbon and actually make some money.
spk10: Got it. That's very helpful there. Thanks. And Switching gears here, and maybe this is a little bit premature, but just wondering, given how profitable the quarter was, if you've had any conversations with the agencies, or if you have any expectations of what this could do, if it could lead to some stabilization, some improvement outlooks there, just curious in general for your thoughts on that.
spk11: We have had good conversations with the rating agencies. Clearly, before we come out with these earnings, we will always sit down and go over the results with them. And likewise, we'll start looking at a longer-term forecast with them. And, yes, we remain very bullish that we should continue to target to get to a higher rating. But first step, obviously, would be to get back to a stable outlook. So we're going to continue to work and communicate with them. We think we do have good relationships with them and are very optimistic.
spk10: Got it. I'll leave it there. Thank you. Thank you.
spk12: Thank you. Our next question is from Pierce Hammond with Simmons Energy. Please proceed with your question.
spk09: Good afternoon, and thanks for taking my questions, and congrats on delivering a very strong first quarter. My question, somewhat following up from the earlier question, pertains to repurposing assets, specifically Permian oil pipelines. And I'm just curious, how hard is it to repurpose an oil pipeline to carry natural gas or NGLs, both from a commercial and a physical standpoint? And lastly, if industry participants do repurpose some assets, oil takeaway assets, what do you see as the impact to energy transfer?
spk08: Okay, this is Mackie again. If you kind of go back to our history, we've done a lot of what you just said. We converted an NGL line out in West Texas. I'm sorry, we converted a trans-western line to NGL service years ago. We converted ETCOP, which was a natural gas pipeline, to crude service. We've converted a pipeline that runs across Texas that was actually in NGL service. And we converted that to a refined product. So it's not a very difficult process, you know, depending on the product and what you're exchanging it with. There may be more cleaning involved and more pigs or whatever, but it's a fairly simple process. It's the assets that you might have to add on one end or the other. If you have to handle liquids, you may have to add some liquid handling facilities and things like that. But just the act of converting a line and putting it in different services is actually pretty simple. from a physical perspective. From a commercial, it just all comes down to utilization, the most profitable utilization of those assets. And right now, we have plenty of capacity to move NGL barrels out of the Delaware, out of New Mexico, through an existing 24-inch, another line. So this gives us the ability to convert this. However, in the future, as we think we'll see the NGL growth out there hit kind of some of our expectations, we may be converting it back at some point. But this at least saves us a significant amount of capital, and we're able to move very quickly. Because this capital that we're spending on a Permian Bridge, it's a very short term. We'll be seeing revenues on this by, you know, latter part of the third quarter and early part of the fourth quarter. And then I didn't really follow your question about how it pertains to the industry. on these conversions? Could you ask that again?
spk09: Yeah, I just meant if some other pipelines were to convert or repurpose, how would that impact energy transfer?
spk08: Well, it depends on what they convert. If they're converting a line that competes with us to a different commodity, of course, that would benefit us. But I think all companies right now in the midstream, especially in Texas, are looking at their assets. There are certain segments that are overbuilt. That's very evident. And so I think everybody's looking at that. But we pretty much focus on what we have, the products that we're moving through, our pipelines, and how do we better utilize them to provide more revenue for our unit holders.
spk09: Thank you, Mackie, for the helpful answer. And that was my only question, so thank you.
spk00: You're welcome.
spk12: Thank you. Our next question is from Becca Followill with U.S. Capital Advisors. Please proceed with your question.
spk13: Hi, guys. Does the guidance that you've given, the updated guidance, incorporate recovering all the sales of gas, even those that you haven't booked? In other words, could there be upside to guidance if you do resolve some of the credit disputes?
spk11: Yes, there could. But we have scrubbed them really well, Becca, and feel like that where we are right now is pretty solid. But there is some upsides depending on how some disputes are resolved.
spk13: Thank you. And then the second question is, how much of 2022 and 2023 CAPEX that you've laid out is for energy transition opportunities?
spk08: This is Mackie again. At this point, not a whole lot. As Tom mentioned, a lot of what he's working on, his team, are not high capital projects anyway. So we don't have a lot of that in there yet. We certainly, as we get close to the finish line and to FID on some of these projects, which we're moving along very well on some of them, then we'll look at doing that. But remember in 22 and 23 on the ranges that we've given, there's some cushion in that range. I mean, we know that there's you know, we're going to always be tying in wells or doing things like Permian Bridge where we're saving capital and connecting different areas. So, you know, we have some room to add some capital without changing that outlook.
spk11: Great. Thank you. Becca, this is Tom. Let's clarify one part of the first part of your question real quick. The reserve that you're talking about or the upside is Just to make sure, if there's any additional settlements as we go out, the guidance we've given you is with everything that we've got right now, it's not baking in any additional type upsides to settlements.
spk12: Thanks. That's how we understood it. Thank you. Thank you. Our next question is from Michael Bloom with Wells Fargo. Please proceed with your question.
spk01: Thanks. Good afternoon, everyone. I wanted to ask about Marcus Hook. I know in the past, you know, you had talked and you had discussed building that out kind of as a big hub, export, all kinds of stuff at the location. Can you just talk about where that stands today, both from an export capacity perspective and then other things you were thinking about? You know, how has that been developing?
spk08: This is Mackie Michaels. You bet. As you can imagine, we are so excited to be at the tail end of a project that's gone on for a while. But what an incredible franchise. I mean, there's really no way to get, you know, or the most economic way to get barrels out of western Pennsylvania and eastern Ohio and West Virginia is the Mariner franchise. So as we complete the final phases of the Mariner projects, we couldn't be more excited. Every time we kind of complete a phase, we ramp up and we're loaded up. So we're moving as many barrels as we can through that pipeline today. With this next phase that we're completing over the next 30, 45 days, we'll be able to ramp that up as well. And then as the final phase is completed, hopefully by the end of the third quarter, we'll be in a really good situation to be able to fully utilize all of our cooling and storage and capabilities at Marcus Hook. As you probably know, we have a significant footprint there with just an incredible amount of capability of expanding. Since the pandemic's kind of, we're coming to the tail end of the pandemic, we have increased our conversations around additional ethane opportunities and also the propane-butane growth will continue to improve from that terminal. So we're very excited on what we'll be bringing into that terminal. and the additional projects that we'll bring that some of what we've talked about and some that we're working on. So similar to Nederland, it's an incredible terminal. We're the only company that has the ability to do that, as you know, off the East Coast and also out of the Gulf. And what a great asset to have. We're excited about it.
spk01: Great. And then on a related note, as you are getting closer here with Mariner East, getting that to the finish line, Can you talk about where you stand from a contractual perspective? How much is contracted today for how long? And do you think once you get the full system up and running, you'll be able to contract more of the pipeline? And is that the strategy? Thanks.
spk08: Absolutely the strategy. We've built a lot of pipeline capacity. And once we complete in the third or fourth quarter, we will be fully utilizing that. all of our very quickly ramping up and utilizing all of our chilling and our storage capacity at Marcus Hook. We're looking at some fairly inexpensive expansions for some level of volumes to also increase our volumes through Marcus Hook. And as I alluded to earlier, we're also looking at some bigger expansions, both around ethane and around propane and butane. So The pipelines give us tremendous opportunity to grow with very little capital just by adding pumps. So the additional capital will come with adding more chilling and more storage at Marcus Hook.
spk01: Thank you.
spk08: Thank you.
spk12: Our next question is from Christine Cho with Barclays. Please proceed with your question.
spk02: Thank you. I just want to talk about, you know, you guys just had this big windfall and I recognize that you have a priority for debt pay down. But, you know, that has been accelerated. So how do you think about, you know, there could be some potential selling pressure in the upcoming quarters from current owners of Enable. What are your thoughts of buying back stock to offset some of the dilution from the deal and the selling pressure?
spk11: Yeah, Christine, clearly that's something that's on the drawing board as well as distribution discussions. And you used the right term when you said accelerated. This has accelerated the plans that we've been laying out. So we're obviously very, very excited about it, and we will continue to evaluate that based upon market conditions.
spk02: And, you know, with respect to just the broader maybe capital allocation plan, When should we expect that? Is that something like we can hear, you know, 2022, or is it beyond that?
spk11: Christine, we're looking at it more from a leverage metric, meaning getting to the four and a half, and that's the guidance that we've not put out there. But like I said in the prepared remarks, this accelerated by nearly a third of a turn, getting to that that much quicker. So we're very, very excited once again to be able to bounce the ball down the field, so to speak.
spk02: Great. And then maybe I'll just end with, with respect to DAPL and the Supreme Court process, can you just give us some color on what the next steps are here and the timing for each of those steps? And we've heard, you know, just a lot in the last couple of weeks about shippers having set up alternative takeaway to prepare for a worst-case scenario. And I recognize that that scenario is kind of off the table, but would you say that that has impacted volumes on the system today?
spk08: This is Mackie. What's really impacted the volumes on DAPL has been drilling. I mean, we were at 1.6 million barrels a day before the pandemic, and now we're down around 1.1, 1.2. So that certainly has impacted it to a certain degree, but we're seeing it come back. There's a lot of ducts that on the process being completed. And so there's also some comments from some of the bigger producers. They're going to start moving rigs. But the volume fluctuations on that are more related to the lack of drilling up there in that area.
spk02: Got it. And the Supreme Court process?
spk07: Yeah, this is Tom Mason. You know, we made a filing to kind of put us in line to go to the Supreme Court if we need to. We don't really anticipate that we'll need to go that route. Judge Boasberg is going to rule on the motion for injunction sometime in the near future. We expect a favorable result from that, and if that happens, then we continue down the environmental impact statement preparation process that the Army Corps is working through. And we just, you know, kind of business as usual, continue to operate the pipeline and continue to work through the EIS process. I don't The Supreme Court route is probably not some of the top of our list.
spk02: Okay. Great. Thank you.
spk12: Thank you. Our next question is from Keith Stanley with Wolf Research. Please proceed with your question.
spk06: Hi. Thank you. I guess first just a clarification on the storm. Sorry to beat a dead horse, but the $2.4 billion storm benefit, is that Is that the amount that's in the Q1 EBITDA figure, or is it even more than that? Because I think, Tom, you alluded to having $100 million of lingering costs over the balance of the year from the event.
spk11: That is correct, Keith. It was more. What we baked in was the full year 2021 when we gave you the 2.4.
spk06: Got it. Okay. Second question on... on enable. I just noticed in the press release, I'm not sure if this is new or not, you say you expect FTC to grant unconditional clearance for the transaction. Is that just a reference to not expecting to have to sell assets or take other mitigation actions? Just curious on the use of that term.
spk07: Yeah, this is Tom Mason. That's exactly right. We can work through a process of providing additional information to the FTC on the second request, but you're exactly right. We don't expect to divestiture or consent decree that would limit, you know, some kind of operational issue.
spk06: Got it. Thank you.
spk12: Thank you. Our final question is from Jean Ann Soulsbury with Bernstein. Please proceed with your question.
spk03: Hi. Congrats to you and your people on the ground on a very good quarter. Just a couple for me. According to your 10-K, last year you had about $430 million and reductions on crude pipelines, I think primarily due to roll-ups on Permian Express. Could you comment on where we are in kind of this roll-up lifecycle? Would you expect comparable rolls this year, or is the worst, you know, behind us with that 430?
spk08: This is Mackie. Yeah, we actually this year, I don't believe we have any contracts rolling off. We might have one or two next year, but we certainly have embedded in any of our guidance rolling those over where market prices are today. And we've got kind of a new team leading our crew group, and we couldn't be more excited. Over the last three or four months, we've grown our volumes by 20%, 20% to 25% from where we'd been. We're getting more creative. We're looking as far down as we can from Midland, taking it all the way up through Mid Valley to the refineries. So there's a tremendous amount of upside there. on our crude business, and any contracts that are rolling off, we expect to extract better spreads than what we're seeing in the market today. In fact, I got a text right before this earnings call that we just closed a deal, a fairly long-term deal, at spreads wider than what they are today because of the ability to offer, you know, to offer Needland, to offer St. James, to offer storage and blending opportunities. And so that's how we're approaching this. We're not just looking at it at the spread from point A to point B. We're looking at it as a full service from the wellhead to wherever the producer or the market wants to take the volume. So very excited about that.
spk03: Great. That's super helpful. Thank you. And then it feels like the LNG market has inflected just even near to date. Just wondering if there's been any uptick in interest in Lake Charleston.
spk07: Yeah, this is Tom Mace again. You know, there has been an uptick in prices both in Europe and in Asia, and so we are experiencing increased interest and have a lot of productive discussions with customers all over the world. So, you know, it could be making a good turn to get that project moving forward in a positive way.
spk03: Great. Thanks. That's all for me.
spk12: Thank you. Ladies and gentlemen, we have reached the end of the question and answer session. I will now turn the call over to Tom Long for closing remarks.
spk11: Once again, we really do appreciate all of you joining us today. As I mentioned, we're very excited about the performance of our existing asset base and all the projects we have coming online. And we look forward to talking with all of you with any follow-up questions you might have. Thank you all.
spk12: This concludes today's conference and you may disconnect your lines at this time. Thank you for your participation and have a great day.
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