Energy Transfer LP

Greetings and 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 anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Tom Long, Chief Financial Officer. Please go ahead, sir.

Thank you, Operator, and good afternoon, everyone, and welcome to the Energy Transfer First Quarter 2020 Earnings Call. And we really want to thank all of you for joining us today. I'm also joined today by Kelsey Warren, Mackie McCree, and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, all of you have seen 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 upon 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 10Q for the first quarter of 2020. 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. And we expect our 10Q to be filed later today. The current COVID-19 pandemic has impacted our nation in more ways than one. As we navigate through this uncertainty, we want to start today by thanking our team of more than 12,000 men and women across the country for their remarkable contributions and incredible commitment during this challenging time. We understand and appreciate the tremendous amount of hard work and coordination it requires to keep our assets running safely and efficiently while keeping energy products moving both for the benefit of our partnership and our country. Now before addressing the current market conditions brought on by COVID-19 and the OPEC oversupply I'm going to start with a few of our first quarter 2020 highlights. For the first quarter, we generated adjusted EBITDA of $2.64 billion and DCF attributable to the partners of ET as adjusted of $1.42 billion. And our coverage ratio for the quarter was 1.72 times, which resulted in excess cash flow after distributions of $594 million. Adjusted EBITDA was adversely affected by inventory valuation adjustments of $213 million in the first quarter of 2020, which I will discuss further in the segment reviews. Without these adjustments, first quarter adjusted EBITDA would have been approximately $2.85 billion, and both adjusted EBITDA and DCF results would have been above our expectations. During the first quarter, we also brought our seventh fractionator at Mont Bellevue online, which brings our total fractionation capacity at Mont Bellevue to over 900,000 barrels per day. Additionally, our 200 million cubic foot per day Panther II processing plant in the Permian Basin was placed into full commercial service in January of 2020. Finally, in January, we completed dual offerings of debt and perpetual preferreds in the aggregate amount of $6.1 billion. A portion of the proceeds from these offerings were used to redeem all of our 2020 maturities with the remainder used to pay down short-term borrowings on our credit facility. We had a strong liquidity position of approximately $4 billion at the end of the first quarter. Additionally, we have a very manageable $1.4 billion of maturities in 2021. Now looking at our 2020 outlook, although the current year has become increasingly challenging in the energy industry and has resulted in lower financial projections across the midstream space, we believe that our fully integrated, diversified asset base offers unique benefits and a foundation that has been built to help mitigate cyclical markets. In light of the significant weakness in crude oil prices due to the COVID-19 demand disruption and additional OPEC supply, we are revising our 2020 adjusted EBITDA guidance range to $10.6 to $10.8 billion. In addition, as producers curtail drilling and in some situations shut in existing wells, we do expect some short-term volume reductions in crude associated with gas and NGLs. Helping to offset the impacts from lower volumes and lower commodity prices, we expect increases related to the addition of the SIM group assets, as well as contributions from the ramp up of Mariner East, Fract 7, new processing in the Permian, as well as full year contributions from projects that went into service in 2019. We are also taking additional steps to keep our assets running efficiently and our cash flows steady as we navigate the tough market conditions and challenges ahead. These include cost reduction measures and reduced 2020 growth capex expenditures. Commercially, our team is focused on locking in existing volumes for longer terms, and this continues to take precedence over development of new assets. Operationally, we are leveraging our extensive infrastructure to help drive operational efficiencies and optimize our assets. As a result, Through the combination of our diverse asset base and a lot of hard work from our talented employees, we have found some new opportunities during this disruption. The wide and profitable contango spreads on virtually all of our hydrocarbon products is allowing us to capture significant margins utilizing our extensive network of storage assets. Through the end of 2020, we have contracted 6.2 million barrels of crude oil storage capacity in the Department of Energy's Strategic Petroleum Reserve. We have a connection to the reserve through our needle and terminal, so this is an efficient extension for our franchise. In addition, due to this pressure on our business, we have identified and are executing on significant cost-cutting initiatives, both in our corporate offices as well as our field operations. As a result, we expect to save $200 to $250 million relative to our 2020 budget. We have also further reviewed our growth capital expenditures for 2020, including project spend today, completion dates, economic impact on delaying particular projects, and near-term cash flows. Approximately 70% of the growth capital spent in 2020 will be spent on projects that are 60% or more complete and are expected to be in service in 2020 or early 2021. This includes Mariner East, the Lone Star Express expansion, and the Orbit and other LPG export projects at Nederland. However, we have decided to delay some projects, including FRAC-A and select Canadian projects, as well as change the scope of the Ted Collins pipeline. Based on our outlook for the current market, we are reducing our 2020 growth capital expenditures by at least $400 million to $3.6 billion and we are evaluating another $300 to $400 million for potential reduction this year. Although we anticipate growing the business over the next several years, and we are continually evaluating new opportunities given our asset footprint, we view it as unlikely we will add any major organic growth projects to our backlog for 2021. As we think about future capital spend over the next three to four years, we anticipate an annual run rate of less than $2 billion. We remain committed to generating free cash flow and still expect to be free cash flow positive in 2021 after growth capital and equity distributions. Looking more closely at our growth projects, I'll now walk through our recent developments. We are transitioning the Ted Collins crude oil pipeline into the Ted Collins link. which will reduce capital spend and increase the utilization of existing assets while providing the same market connectivity between our Nederland and Houston terminals. The Ted Collins link will be a much less expensive and quicker alternative that will allow us to transport up to 275,000 barrels per day from West Texas and Nederland to our Houston terminal and is expected to be in service in the fourth quarter of 2021. The Moore Road pipeline is now in service. This pipeline expands and improves our existing access to and from our Houston terminal and export facilities, as well as access to Houston Ship Channel refineries. Regarding the Bakken pipeline capacity optimization, as we have previously mentioned, the Bakken pipeline received sufficient market interest to move forward with plans to further optimize system capacity. The initial phase of the optimization above the pipes current capacity of 570,000 barrels per day, will accommodate the volume commitments made by shippers during the recent open season. Subject to completion of the permitting process, we now expect this additional capacity to be in service in the second quarter of 2021. Now moving on to Mariner East system, total NGL volumes through the Marcus Hook Industrial Complex averaged 226,000 barrels per day during the first quarter. with 17,000 barrels per day coming in by other modes, including rail and third-party pipelines. At the beginning of this year, we reached an agreement with the Pennsylvania Department of Environmental Protection that will allow us to complete the construction of projects we have underway in Pennsylvania. And in April, we started to ramp up some additional volumes on the Mariner East system. Customers at our Marcus Hook complex are taking advantage of the flexibility that our Mariner East system has to offer by placing barrels for the upcoming winter season into local markets. We are pleased to be connected to the new CPV Fairview Power Plant in Cambria County for the local ethane supply from Mariner East for Pennsylvania power generation. This connection enables further market flexibility for shippers on the Mariner East system while advancing local energy initiatives with efficient transportation options. At the same time, International demands for propane and butane has remained strong, even while motor fuel demand has waned because of COVID-19. This is helping our Appalachian producers find a market for their products. Looking ahead, we are anxiously awaiting the next phase of the project, which we now expect to be in service in the first quarter of 2021, while the final phase completed in the second quarter of 2021. In addition, We continue our expansion at the Marcus Hook Terminal as it provides customers with the most efficient way to reach the best markets for their product. This expansion will provide approximately 50,000 barrels per day of incremental NGL throughput capacity at the terminal in the first quarter of 2021, accommodating volume growth from Mariner East. Moving on to our Lone Star assets, Frac 7 is now in service and has ramped up as expected. As mentioned, we are delaying the construction of Frac 8 based on our current supply and volume expectations, along with our customers' volume expectations. We now expect to be in service in the first quarter of 2022, and we are in the final stages of construction on our 24-inch, 352-mile Lone Star Express expansion which will add over 400,000 barrels per day of NGL pipeline capacity from the Permian Basin to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. We continue to expect the expansion to be in service in the fourth quarter of 2020. In light of the current conditions, we have converted some of our storage facilities at Mont Bellevue to allow us to store a significant amount of natural gasoline and diesel barrels into 2021. which provides us with significant contango revenue. This demonstrates another valuable benefit of our dynamic franchise. Looking at our LPG expansion project at Nederland, we have recently found a very cost-effective way to modify this expansion, which will increase the capacity from 235,000 barrels per day to 300,000 barrels per day. LPG demand has remained strong, as has demand for this project, which will further integrate our Montbellevue assets with our Nederland assets to expand our LPG export capabilities. Construction is progressing well, and it remains on schedule to be in service in the fourth quarter of 2020. The conversion of the White Cliffs pipeline from crude oil to NGL service is complete, and volumes on this pipe, which runs from Platteville, Colorado to Cushing, Oklahoma, began flowing in December of 2019. Construction on our orbit ethane export joint venture with satellite petrochemical is nearing completion, and we expect the project to be ready for commercial service in the fourth quarter of this year. Turning to gas processing in West Texas, our 200 million cubic foot per day Panther II processing plant in the Permian Basin was placed into full commercial service in January of 2020. With the completion of this plant, which is fully subscribed We are now capable of processing more than 2.7 BCF per day in the Permian Basin. Let's take a little closer look at the first quarter results. Consolidated adjusted EBITDA was $2.64 billion compared to $2.74 billion for the first quarter of 2019. The change from the prior period was primarily due to crude oil and NGL and refined products inventory valuation adjustments of $213 million that adversely affected adjusted EBITDA in the first quarter of 2020. Crude oil and NGL refined products had a positive impact of $27 million in the first quarter of 2019 for a total impact of $240 million from the first quarter of 2019 to the first quarter of 2020. DCF attributable to the partners as adjusted was $1.42 billion for the first quarter down $177 million compared to the same period last year. This is primarily due to the decrease in adjusted EBITDA. Distribution coverage ratio for the first quarter was 1.72 times. In March, Energy Transfer announced a distribution of 30.5 cents per common unit for the first quarter, or $1.22 per common unit on an annualized basis. This distribution is consistent with the fourth quarter of 2019 and will be paid to unit holders of record as of the close of business on May the 7th. Let's look at results by segment. Starting with NGL and refined products, adjusted EBITDA was $663 million compared to $612 million for the same period last year. This increase was due to record frac and NGL transportation volumes which were partially offset by a $59 million impact from changes in inventory valuation adjustments in the first quarter of 2020 versus a $9 million valuation adjustment in the first quarter of 2019. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.4 million barrels per day compared to 1.2 million barrels per day for the same period last year. The majority of the increase in volumes was on our pipelines out of the Permian Basin and North Texas regions, as well as on our Mariner East pipeline system. First quarter average fractionated volumes increased to 804,000 barrels per day compared to 678,000 barrels per day for the first quarter of 2019. For the crude oil segment, adjusted EBITDA was $591 million compared to $744 million for the same period last year. This was primarily driven by a change in inventory valuation adjustments of $190 million. In the first quarter of 2019, we had a positive $36 million adjustment, and in the first quarter of 2020, we had a negative $154 million adjustment. In the first quarter, a portion of the barrels previously recognized as operational inventory have been reclassified as a long-term asset, which is expected to help reduce the volatility of earnings in the crude segment. Going forward, based on our current business operations, we expect our inventory that is subject to these adjustments to be between 3 to 4 million barrels. Crew transportation volumes increased to 4.5 million barrels per day compared to approximately 4 million barrels per day for the same period last year, primarily due to increased barrels out of our existing Texas pipelines, volume growth in the Bakken, and the initiation of service of phase two of the Bayou Bridge pipeline in the second quarter of 2019, as well as the acquisition of Sim Group assets in the fourth quarter of 2019. For midstream, adjusted EBITDA was $383 million compared to $382 million for the first quarter of 2019. Higher midstream throughput volumes were partially offset by lower NGL and gas prices, which impacted results by $22 million. Gathered gas volumes were 13.3 million MMBTUs per day compared to 12.7 million MMBTUs per day for the same period last year. This increase was due to volume growth across the majority of our operating regions and demonstrates the strength of both our customer base and our asset footprint. In our interstate segment, adjusted EBITDA was $404 million compared to $456 million for the first quarter of 2019. This was primarily a result of a contractual rate change at the Lake Charles facility. as well as lower demand for services on several of our pipes. And in our intrastate segment, adjusted EBITDA was $240 million compared to $252 million in the first quarter of last year. This was primarily due to higher transport fees from the ramp up of the Red Bluff Express, increased storage margin from a higher storage optimization, and new contracts. These were offset by lower revenues from pipeline optimization. activities. Let's now look at the CapEx. For the quarter ended March 31st, 2020, energy transfer spent approximately $1 billion on organic growth projects, primarily in the NGL and refined products and midstream segment, excluding sun and USAC CapEx. And as a reminder, near as 70% of the capital spent in 2020 is on projects which are more than 60% complete and are expected to be in service in 2020 and early 2021. And as I mentioned earlier, for the full year 2020, we now expect to spend approximately $3.6 billion, primarily in our NGL and refined products and midstream segments. And we are evaluating another three to $400 million for potential reduction this year. Looking briefly at our liquidity position, late in 2019 and early this year, we successfully completed financing transactions which provided an efficient funding source and bolstered our liquidity position. This included debt and perpetual preferred dual offerings completed in January 2020 in the aggregate amount of $6.1 billion for which we used a portion of the proceeds to redeem all of our 2020 maturities. The remainder of the proceeds were used to pay down short-term borrowings under our credit facility. As of March 31, 2020, total available liquidity under our revolving credit facility was approximately $4 billion, and our leverage ratio was 4.12 per the credit facility. And as a reminder, looking forward, we have a very manageable $1.4 billion of maturities in 2021. We continue to target a rating agency leverage ratio of four to four and a half times. In conclusion, I just want to reiterate that we are very pleased to have delivered another solid quarter. Throughout the remainder of 2020, we continue to expect our fully integrated, multi-product assets, as well as our predominantly fee-based cash flows to offset headwinds this year. and the ramp up of growth projects which are expected to drive near and long-term value will continue to generate excess cashflow and fund our growth projects. In addition, our extensive storage capabilities combined with our recently leased space at the SPR are providing valuable opportunities to capture upside related to the contango spreads. We remain committed to our investment grade rating and our strong liquidity position provides us with the financial flexibility as we navigate through this uncertain time. However, we know that it is imperative to remain mindful of our spending and we'll continue our disciplined approach to capital expenditures while also pursuing additional cost savings. Safety and project execution remain among our top priorities and we want to once again thank our employees for their hard work and continued support during this challenging time. Operator, let's open the call up to Q&A.

Thank you. At this time, we'll be conducting a question and answer session. In the interest of time, please limit to one question and one follow-up question, then rejoin the queue for any additional questions. 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. One moment, please, while we poll for questions. Your first question comes from the line of Jeremy Tonnet with JP Morgan.

Please proceed with your question. Good afternoon. I just want to start off with discussing, I guess, your assumptions on the recovery post-COVID as far as both on the demand side and the supply side, just trying to think through how you guys view the world, how that factored into your guidance, and if you'd kind of bounce us off the agencies and if they were kind of comfortable with your outlook at this point.

This is Mackie. Yeah, let me start, and then Tom can follow up. As everybody knows, we're in kind of unprecedented times that nobody could ever predict the entire world country to be shut down. So things really got difficult kind of last part of April and then in May. However, how it's impacting our assets in a couple of ways is, for example, in our GMP assets, we have had some volumes shut in. However, just to give you an example, in the Midland Basin, we've had about 8% of the volumes shut in. That was beginning of May, and as of today, we've seen about 25% of that turn back on. So that as an example, as we look through all of our assets and all of our segments, we see that things have bottomed out, in our opinion, and that things are improving and they're going to grow. A lot of it, of course, depends on WTI. Where's WTI going to go? We are pleased by how it's kind of strengthened and hanging in the mid-$25 range, and the curves kind of show it growing throughout the rest of the year, and we're pretty optimistic that's going to be the path that we're on. So from an energy transfer perspective, we think things have bottomed out. How quickly they'll grow remains to be seen, but we do expect, if not faster growth, at least gradual growth for the next quarter. And we've injected that in our projections and in our discussions with the rating agencies.

And I'll chime in. Jeremy, I'll chime in here real quick on the rating agency part of it. We do continue to work with them very close as they continue to evaluate projections and et cetera. As always, we feel like we have great credibility with them. We're going to continue to work with them. We're also highlighting all the other levers, various levers that we have to pull to The CapEx, like we've talked about, that aspect of it, the cost, several things that we've looked at. So all in all, our dialogue with the agencies continued, and we will, like always, just give them the best information, the best forecast we have.

That's helpful. Thanks. And just wanted to touch on the CapEx side. What would get you to the other side as far as pulling that? point down the incremental three to four hundred CapEx that's under evaluation. How do you see CapEx trending in 21 at this point?

That's Macky again. We look at our projects. We look at the realization and timing of filling those projects and some of the hurdles that we have. In addition to that, we consistently look at those projects that, as we've talked about, are down the road a ways, but where it might make sense to push some of those dollars further out into 21 or even further in some cases. So it's a, you know, it's not day-to-day, certainly a weekly analysis that we make, and those are real dollars that we believe are quite possible that we could push out of 2020, you know, getting us closer to that $3 billion range. But, you know, there's a lot of unknowns right now. You know, certain things could happen in the Middle East. We heard Saudi Arabia cut another million barrels today. I mean, there's things that could really turn this around in a big way that would cause us to continue on the path we're on and bring those projects on timely. But we're certainly looking at it closely, and we'll do everything we can from the standpoint of delaying costs where it's prudent and where it makes sense.

And we're not trying to give guidance for 2021 right now, but I will say that $2 billion or less we do feel good about right now for 2021 and beyond.

Great. That's helpful. That's it for me. Thanks.

Your next question comes from the line of Schnoor Vershoony with UBS. Please proceed with your question.

Hi. Good afternoon, everyone. Maybe to start off, Mackie and Kelsey, just wanted to touch on the CapEx side. I realize it's difficult to make adjustments to the 2020 CapEx numbers when you've got so many big projects that are in flight right now. Tom just mentioned CapEx under $2 billion for the next three to four years. Is there a scenario where 21 could be materially lower than $2 billion if we kind of have an environment that we're in right now or a little bit better than where we're in right now? I'm just trying to understand how low can CapEx go if you know, we're in an oversupply situation for crude, you know, heading into next year.

Yes, you know, this is Mackie. Here's how I'd answer that is that the projects, even some of the projects that we've deferred, we have commitments and in many cases demand charges that are kicking in. So it really doesn't make sense at some point to delay those projects past a certain point, a certain kind of deadline for those So when the commitments and the demand charges kick in. So to answer that question, do we think it could materially and say knock it down to a billion or less? That's unlikely. I think Tom said it well. We expect to be between a billion and a half and two billion dollars over the next three or four years. But certainly, depending on circumstances, we'll continue to evaluate that up or down. But that's a pretty good range right now.

Okay, I appreciate the color. And maybe as a follow-up for Tom, Appreciate the slides that you guys shared with us today. And you have the sensitivities updated now for 5% to 10% for commodities and spreads and so forth. Just trying to understand the sensitivity around that. So when I look at that today, do I look at your current guidance today and say there's 5% to 10% of exposure there? But is that based on where NGL prices are today and gas prices are today and where spreads are today? things would have to be materially worse to see the downside with respect to those types of sensitivities?

Yes, it is. That's the short answer. It is based upon our current prices, both prices and spreads.

Perfect. Thank you very much, guys. Appreciate the color, and please stay safe.

Thank you.

Thank you. Your next question comes from the line of Jean Ann Salisbury. with Bernstein. Please proceed with your question.

Hi. It seems like your expectation around spread earnings have fallen by a few hundred million dollars since the beginning of the year guidance, which is somewhat surprising given the contangos in crude and refined products. Can you just say what the moving pieces are in that bucket, maybe the inventory valuations in there?

As far as the inventory valuations, we do not have that baked in to the guidance, other than what we've reported here in the first quarter.

I'll follow up to that. Certainly, the spreads across Texas on our crude business have tightened. However, offsetting that is we're seeing in our storage business, significant contango spreads that we haven't seen in a long, long time that kind of counteracts the negative impacts to the narrowing spreads on the crude business.

Okay. It looks like overall it went down, though, I guess, versus the last time. So I guess the crude pipeline spread loss is bigger than the contango spread today. I just want to make sure I kind of get it.

I need to make sure I'm following your question on this one. You're saying went down. Oh, as far as the guidance goes?

Yes.

Oh, yes, yes.

Okay, cool.

You are correct.

Thank you. And then is there – it's kind of related to Jeremy's question earlier, but is there a decline in overall U.S. or Permian production that you're using this year to kind of get to this forecast and kind of anchor that if it's better or worse than that, then you'll be better or worse than that?

This is Mackie. I'll start. As I mentioned earlier, we have seen some shut-ins and certainly significant slowing down. However, based on where WTI is now and our optimism that we think that we'll see it kind of hang in there and start to strengthen, we think volumes will recover maybe faster than some others over the next 30 to 60 days. So we don't anticipate, notwithstanding some significant circumstances, we don't anticipate volumes staying down where they are for any significant period of time.

That's really helpful. Thank you.

Your next question comes from the line of Michael Blum with Wells Fargo. Please proceed with your question.

Good afternoon, everybody. Maybe just to make sure, just clarify, one of the questions was just asked So in the slide deck, the 2.5% to 5% of the pie that is labeled as spread, does that capture for your 2020 guidance, does that capture your contango upside this year? I just want to clarify that.

Yes, it does.

Okay, great. My other question was just on FRAC 7 that just went into service and then FRAC 8. Is FRAC 7 fully contracted, and where does FRAC 8 kind of stand at that point? Or do you still have capacity left to turn out there?

Yeah, this is Mackie. FRAC 7 is completely full. It's running at 97%. If you look at all of our FRACs, we're running significantly above the nameplate of those. And so those volumes were, of course, designated to go to FRAC 8. we're able to extend FRAC 8 out to 22 because of the additional capacity that we have above nameplate. But right now, you know, we have a lot of NGLs in storage that we brought it on, and so some of it's coming out of storage. But we've been running our FRAC full and will for a number of days and months at its current status.

Great. Thank you.

All right.

Your next question comes from the mind of Michael Labidus with Goldman Sachs. Please proceed with your question. Hey, guys.

Thank you for taking my questions. Just looking at slides four and five, you know, the pie chart on slide four where you show the adjusted EBITDA breakout in 90% to 95% fee-based, can you break that large piece of the pie into what percent of that is take or pay? And what percent of that is you've got the fee or the tariff set, but you've got volumetric exposure?

Well, Michael, I'll start with that one. Probably if you turn to slide five in the deck, that's the way we've captured it for 2019. Don't know that that's necessarily moving a lot. We obviously can follow up with you afterwards. But I think you can kind of see how much of that, at least from a midstream standpoint, is fee-based, you know, versus keep hold, POP, et cetera. And then if you look at the other pie chart beside it, you'll see the MVCs.

Is that the question you're kind of... Yeah, except I'm not just referring to the midstream segment. I'm referring to the entire business. So if I look on slide five, the table on the right-hand side, like, very easy question. How much of the EBITDA of crude oil is take or pay? versus volumetric, albeit fixed fee, but volumetric. And same thing on interstate transport. Like, how much of that is take or pay?

And, Mike, we don't have that broke out here right now. We'll have to follow back up with you later. Got it.

Happy to follow up with Bill and Team Offline. Hey, just one other question. Can you all clarify a little bit about the in-service dates on Mariner E2X and just kind of – what you're seeing and when you expect the in-service. I know you mentioned it on the call in the prepared remarks, but can you just clarify the timeline for that?

You bet. This is Mackie. Well, first of all, we are bringing on additional capacity, about 25,000 barrels June 1st. So that's very positive, and that is already committed with demand charges. And then we now have moved slightly from fourth quarter of this year to first quarter of next year. Our next significant expansion completion of Mariner, and then the final 2X we expect to be completed in the second quarter of 21.

Got it. Thank you, guys. Much appreciated.

Thank you. Your next question comes from the line of Spiro Dunas with Credit Suisse. Please proceed with your question.

Hey, afternoon, everyone. Just want to go back to the cost cuts. You all mentioned in the slides, it's like $200 to $250 million for this year versus budget. How much of that showed up in the first quarter? And I guess how should we think about you realizing that the rest of the year and then more broadly, how much would you characterize as sustainable so we could see it happen again in 21 versus maybe just deferring out some costs?

Listen, this is Tom. Do you mind starting over with the question? When you started off, it came through a little fuzzy.

Yeah, no worries. Hopefully this time works better. Just on the cost cuts, the $200 to $250 million, just curious how much of that showed up in the first quarter? And then how should we think about you realizing that those savings for the rest of the year, in other words, how much of that is really sustainable versus just deferred?

No, I would put all of it really as sustainable. And as far as how it's spread through the year, it's going to be spread very evenly. through the year, if you really take the first quarter and evaluate that and then kind of go through. Remember, this is G and A and off X. So if you will kind of spread those throughout the year, you'll see those. And we may actually, as we continue to evaluate, we may be able to identify additional amounts there.

Okay, perfect. Second one just on M&A. We'd love to get your mindset as far as that goes now. It would seem like this is an opportune time to consolidate the industry here. You guys have obviously not been shy about doing that in the past where you could, so we'd appreciate your view right now on the M&A landscape, both on individual assets but also just on corporate M&A too.

Yes, this is Kelsey, and you're correct. It's just part of our business plan and always will be. uh, we are, uh, it's all hands on deck right now to, to, to make sure our business is healthy and performing. But, but it is something that, that is, that we, we look at every day. We talk about it every day. I will tell you that the one thing, if there's any, any guidance I can give you on this is that we would not do anything that was not deleveraging. So, um, so you can then begin to look at, at possibilities that may or may not be there. And, and, uh, that would certainly need to apply to whatever possibilities there were.

Very helpful. Thanks, everyone. Be well.

Your next question comes from the line of Christine Cho with Barclays. Please proceed with your question.

Thank you. So if I could start with the CapEx, you know, you guys say that 70% of this year's CapEx is for projects, you know, that are more than half complete or supposed to be in service this year or next year. For the $300 million to $400 million that you're evaluating to further reduce, would you say that is looking to reduce spend on the projects that are supposed to come online this year or next year, and you're maybe thinking about deferring it? Or are those reductions mostly tied to projects that are contemplated to be in service post-2021?

This is Mack Alstar, if time will follow up. But it's a little bit of both. On some of the projects, we are optimistic and hopeful that we do come in under what our expectations and what our budget is. And then some of these are whether we get them completed by the end of this year or push them into next year. And then kind of the third basket is, are there some that, as we evaluate it, as I said earlier, over the coming weeks and months, does it make sense to defer those and push some of those projects in next year and out of 2020?

Okay, that makes sense. And then if I could go move over to the DAPL expansion, can you tell us how much you're expanding it and what sort of flexibility do the customers have to potentially push back this in service dates? if you know we are in a prolonged downturn I'm just trying to reconcile you know the need for additional capacity versus the current outlook for production in the basin and would be curious if this is one of those projects in that three to four hundred million being evaluated uh certainly it's in that that one of those baskets but uh right now you know dapple's been such an incredible project and it's been such a shot in the arm for

for North Dakota and really for our country. So it's gone exceptionally well. Our open season went exceptionally well. We do expect to have expanded in 2021, and we're hopeful to get the final regulatory approval soon. However, that doesn't mean that depending on circumstances and depending on shippers and shippers' interests and different approaches that there might not be some options or some things we can do. But the bottom line is we have commitments. These are demand charge-based commitments for long periods of time, and if other arrangements are not made and we're in service the second quarter of 2021, those commitments will kick in.

And are you able to tell us how much you're going to be expanding by?

The open season is completed, as you know, and right now we anticipate expanding by you know, somewhere in the 740, 750,000 barrel range. That certainly can change as discussions go on, but that's kind of a ballpark. Great. Thank you so much.

Your next question comes from the line of Pierce Hammond with Simmons Energy. Please proceed with your question.

Yeah, good afternoon, and thanks for taking my questions. Two questions here. First, other midstream companies have highlighted some strength in the LPG export business, and it sounded like in your prepared remarks that you're seeing the same, so I wanted to get some color from you on that. And then the second question, which dovetails with the first, which what is your outlook for ethane, propane, and butane demand this year? Thank you.

Just Mackie again. What an exciting part of our business. We needed to build fracks after all the transportation we signed up. Then we needed to find a home after we kind of saturated the industry, kind of saturated the domestic market. We kicked off MentorSouth a number of years ago, and that's gone exceptionally well for us, and we're close to adding another, as you heard, 300,000 barrels of LPG capability, and it's much needed. With all the downturn and all the turmoil and everything that's been going on the last 30, 45 days, that's been a shining light. We have Tremendous amount of demand. We're in constant conversations. We're in the process of selling out whatever capacity that we're adding for some periods of time, and we see that to be a significant growth vehicle for our partnership for many years to come.

And then my quick follow-up pertains to storage upside as well as on the SPR. But tell us a little bit more about the upside that you've got from your storage capabilities, and what does it mean being the successful bidder on that leased crude oil storage capacity in the SPR?

Well, as you can imagine, right now having storage of a number of products, of course, including crude, is very valuable. our existing Nederland and other stores that we have around the state and the country has been benefited in a big way and will for the remainder of this year, and the Contango spreads. And likewise, the SPR winning that bid was important from the standpoint of revenue for us and locking in Contango, but it also was as important for our producers. You know, when when it looked like there wasn't going to be any markets and that all these barrels that we buy on a consistent basis and transport on a consistent basis to try to kind of make sure there was a market for all that, we thought it was necessary for our customers to find more space, more capacity for their barrels. And so, you know, things certainly have slowed down on the market side, but we needed that to have that, call it, market for all the barrels that we buy for our customers to make sure our customers' barrels move.

Thank you, Mackie.

Your next question comes from the line of Ujwal Pradhan with Bank of America. Please proceed with your question.

Good afternoon, everyone. Thanks for taking my question. First one on the Hainesville Basin and some of your assets that you have operating there. We have heard from a few of your peers on growing interest in the assets and activity in the basin. Can you speak to what you're seeing or what your expectations are across your gathering assets as well as the Tiger pipeline?

Yeah, you know, the Hainesville has been an interesting area in that, you know, it had tremendous potential and growth for a number of years and then slowed down for a number of years, and now it's got its second leg. I mean, we've On any given day, we're moving to BCF. And the interesting thing and the very beneficial thing about Haynesville and our Tiger system is it's a bidirectional system. So not only can we move east, which is predominantly where gas is always going to go, but where now the interest is is finding its way back into Texas, into our intrastate network, ultimately find its way down to the chip channel into LNG markets. So that's been a very positive growth area for our assets. We expect those to stay, to keep Tiger full for many years to come. Likewise, a lot of the gathering assets we have kind of in North Louisiana, especially the gas that needs treating. Even these times when there's been kind of some areas where gas is, I mean, products are being shut in, we're seeing growth in the leaner gas plays, which is, of course, the Hainesville play. So that's a really... as I mentioned earlier, at a tough time when a lot of, you know, gas and oil is being shut in, we see that as a growth area, even as we speak.

Got it. Thanks for that. And maybe on your expectation for positive free cash flow starting in 2021, could you please speak to the commodity price and spread opportunity assumptions baked in it? and how big of a priority this is for ET today?

Well, we've not put out guidance for 2021, as you know, but I think it is worth talking about when you look at 2019, we had over $3 billion of what we call retained cash flow. That's above the distributions. When you really look at this year and you see where our guidance, where we currently have guidance, you'll see that we have free cash flow We're right at that cusp. When you get to the $2 and less than $2 billion for 2021, you can really look and see what type of now free cash flow we have. And that's what we're going to continue to use as our EBITDA grows, as these projects we've talked about today. That's what we're going to be using to start lowering the debt levels from that standpoint. But we'll probably talk more about later in the year on 2021 Right now, it's about looking at where you think the curves are, where the price deck, when you look out at some of the longer-term price decks.

That's helpful. Thank you.

Your next question comes from the line of Keith Stanley with Wolf Research. Please proceed with your question.

Hi. Thank you. I wanted to start just with two clarifications. On the Bakken pipeline, do you have firm commitments for most of that capacity step up from 570 to 750,000 barrels a day, or is the expansion size larger than the commitments? And then second one was just I want to confirm that the 200 million inventory right down headwind in EBITDA for the first quarter, you're assuming that headwind is in the 10.6 to 10.8 billion range. guidance for the year. So absent that, the guidance would have been even $200 million higher.

I'll start. This is Mackie. I'll start with the first and let Tom on the second. Yes, in our open seasons, we've got commitment for significant volumes, and so the vast majority of the capacity that we're expanding is demand charge capacity. Of course, we've got a whole room for walk-up and that type of capacity, but yes, the majority of it is demand charge.

And as far as the second part of your question, I would say that the $213 million you saw in the first quarter, yes, it is baked into the 10-6 to 10-8 guidance we have.

Okay, great. And then, Tom, on the balance sheet, can you just remind us the leverage target for the company? And you talked about using free cash flow starting next year to potentially be a vehicle to pay down debt. Has the strategy changed at all on how you're approaching the balance sheet and leverage just given what's happened in the oil market?

Obviously, a very, very good question, Keith, and no, it is not. We're going to continue to target that four to four and a half. When you really look out at 2021, I know we keep using the free cash flow term, but we're excited to get into that phase of being able to now start paying down the debt as you see projects come on, as we continue to pull the other levers of lowering some of the CapEx. So a lot of our growth is going to come from nothing more than a lot of the projects you've heard us talk about here today. But nothing changed as far as strategy goes.

Thank you. Your next question comes from the line of Colton Bean with Tudor Pickering Holt & Company. Please proceed with your question.

Good afternoon. So just a quick clarification around the Contenga discussion thus far. I think, Tom, you may have noted that the 2.5% to 5% captured the marketing contribution there, but the footnote looks like there should be some degree of earnings and fee base as well. So is the bulk of the benefit showing up in spread, or is the market base rate that you're charging yourself, is that actually accounting for the majority showing up in fee?

I would not. Let me think through that for a moment. We do have some showing up in the fee, any of the portion that's held by the marketing arm, but I would not say the majority of it, no.

Okay, so fair to say that the market-based rate has not moved up materially, just given what we've seen in the last month and a half or so?

That's correct.

Got it. And then just on midstream, as you evaluate your northeast gathering footprint, can you frame for us the relative dry versus rich exposure, and particularly any condensate handling?

This is Mackie again. Yeah, clearly condensate handling has become an issue, really not just in the northeast but elsewhere. We are working closely with producers that really don't have a lot of options to utilize some of our assets to help them move their condensate You know, how long this will last, who knows. Like we said earlier, we don't think this is going to last a long time and things are going to recover. Demand is going to increase, and we'll find a home for that. But, you know, around the condensate, we really don't see that as a long-term problem, and we're doing everything we can to help producers in the short term. And then I don't know if to answer your entire question or not.

Yeah, that's helpful. And I guess, one, I guess, have you seen any curtailments to date on condensate? And then, two, just kind of your broader rich gas exposure relative to dry?

Yeah, I'm not aware of any condensate that has impacted ours. I'm mainly talking about a condensate that's with other midstream companies where they're looking for help for their home for the condensate. Thank you.

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

Thank all of you once again for joining us today. We really do appreciate your support. We really enjoy talking with you, and we look forward to follow-up calls after this one. Thank you.

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.