Greetings, welcome to Energy Transfer's fourth quarter earnings conference 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. Please note this conference is being recorded. I would now like to turn the conference over to your host, Mr. Tom Long, Chief Financial Officer for Energy Transfer. Thank you, sir. You may begin.
Thank you, Operator. Good afternoon, everyone, and welcome to the Energy Transfer fourth quarter 2019 earnings call. Thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea, and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you had a chance to see the press release we issued earlier this afternoon, as well as the slides that we posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us. 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. We expect our 10-K to be filed this Friday, the 21st. I'm going to go ahead and start today with a few of our full year and fourth quarter 2019 highlights. For the year, we came in above the top of our guidance range, generating record-adjusted EBITDA of $11.2 billion, which is an increase of 18% over 2018, and was driven by record financial and operational results across the majority of our segments for the year. We also reported record DCF attributable to the partners of Energy Transfer as adjusted of $6.3 billion, and our coverage for the year was 1.96 x, which resulted in excess cash flow after distributions of $3.1 billion.
Looking at results for the fourth quarter of 2019, adjusted EBITDA was $2.8 billion and DCF attributable to the partners of Energy Transfer as adjusted of $1.55 billion, which resulted in distribution coverage for the quarter of 1.88 x and excess cash flow after distributions of approximately $725 million. The excess cash flow we generated in 2019 funded approximately 75% of our growth capital expenditures. In addition to our strong financial performance, we set several operational records in 2019 as we transported nearly 23.8 million MMBtus per day of natural gas, 1.3 million barrels per day of natural gas liquids, and 4.7 million barrels per day of crude oil, and fractionated over 700,000 b p d of natural gas liquids or NGLs. Looking at our EH&S metrics for 2019, our total recordable incident rate, or TRIR, was 0.94, and we worked over 18 million hours.
This was significantly better than the industry average of 1.3 for 2019. We are extremely pleased with these accomplishments, which speak to the investment in and focus on safety and environmental compliance, as well as the reliability of our assets. During 2019, we also finalized the acquisition of SemGroup Corporation and placed several strategic growth projects into service, including the J.C. Nolan Diesel Pipeline, the Permian Express 4 Pipeline, two processing plants in West Texas, and our sixth fractionator at Mont Belvieu, to name a few. We also completed our first natural gasoline shipment from our Nederland Terminal on the Gulf Coast. I'm pleased to say that our seventh fractionator at Mont Belvieu is now in service, which brings our total fractionation capacity at Mont Belvieu to over 900,000 b p d.
Now, looking at our guidance for 2020, our adjusted EBITDA is expected to be $11 billion-$11.4 billion. Compared to 2019, we obviously expected some headwinds related to crude and natural gas spreads. In addition, we will see impact from certain contract renewals. The commercial team's primary activities right now center around locking in existing volumes for longer terms and getting out in front of future contract roll-offs to ensure sustainable cash flows in the long term. This has taken precedence over capital expansion and development of new assets. For example, we have recently renegotiated multiple contracts extending several out as much as 15 years with greater long-term volume commitments exchanged for short-term relief.
Helping to offset these impacts will be earnings increases related to the acquisition of SemGroup, as well as contributions from the ramp-up of several growth projects throughout the year, including Mariner East, Frac VII, new processing in the Permian, as well as full-year contributions from other projects like Frac VI, J.C. Nolan, PE4, and Red Bluff Express. For 2020, our organic growth capital expenditures are now expected to be $3.9 billion-$4.1 billion, which is revised from our previous guidance to include approximately $300 million related to the SemGroup assets. Post-2020, the backlog of approved growth capital projects is approximately $1.8 billion, including SemGroup. We expect additional projects to be added to this backlog, but as a reminder, we have raised the bar on return profiles and will continue to be disciplined as we evaluate any incremental spend.
Long term, we now expect our CapEx run rate to be approximately $2 billion - $2.5 billion per year, which we believe will result in positive free cash flow starting in 2021. Let's look at the SemGroup acquisition, which we closed on December 5th of 2019. The combination of these complementary assets provides increased connectivity for Energy Transfer's crude oil and NGL transportation businesses. Since closing, our integration teams have been fully engaged in the combination of these two companies, and we have already made significant progress toward recognizing our projected $170 million of annual run rate synergies. Starting with the financial savings, utilizing Energy Transfer's lower borrowing cost in October, we entered into a $2 billion, three-year term loan A at the current rate of LIBOR plus 100.
The proceeds were effectively used to call all of SemGroup's $1.375 billion outstanding high-yield notes and the $600 million term loan B at the Energy Transfer Houston Terminal, formerly called HFOTCO. This will immediately bring us to over $50 million of annual savings. Looking at corporate cost, we are on track to recognize savings of more than $40 million annually from a reduction in head count and increased efficiencies. We continue to work toward achieving approximately $80 million of commercial and operational synergies, which are expected to be driven by our ability to leverage Energy Transfer's infrastructure to help drive operational efficiencies and increased utilization of assets.
Through this acquisition, we now have pipeline access to the DJ Basin, an expanded presence at Cushing and St. James, as well as access to the Houston Ship Channel deep water docks and refining complex, which expands our connectivity, increases our reach, and will generate opportunities for other aspects of our portfolio as well. In addition, completion of the approximately 80 mi Ted Collins Crude Oil Pipeline will provide access to over 1 million barrels per day of inbound crude oil for deliveries to the Houston and Nederland terminals, as well as to Houston and Gulf Coast refineries. It will also allow us to fully utilize our 1+ million barrel per day of export capacity at our Houston and Nederland terminals, which we have the ability to expand to over 2 million barrels per day.
The pipeline is expected to have initial capacity of more than 500,000 b p d, and commercial operations are expected to begin in the second half of 2021. In addition, the Moore Road Pipeline, which will expand and improve existing access to and from Houston Terminal, as well as to allow us to export more barrels, is expected to be in service in the first quarter of this year. As for the latest developments on other growth projects, we will start with Bakken capacity optimization. As we have mentioned, the Bakken Pipeline received sufficient market interest during December of 2018 open season for us to move forward with plans to further optimize the system capacity.
The initial phase of the Bakken Pipeline optimization above its current capacity of 570,000 b p d will be based on commitments made by shippers that we have already received, as well as commitments made during the current open season. We still expect this capacity to serve the commitments received to be in service in early 2021. As Bakken volumes and customer demand continue to grow in the future, we will be in position to efficiently increase the system capacity up to 1.1 million barrels per day of permitted capacity over time. For PE4 expansion, which added an additional 120,000 b p d of capacity to our Permian Express pipeline system from Colorado City to Nederland, Texas, went into full service on October the 1st and ramped up nicely in the fourth quarter.
On our VLCC project, which is planned from our Nederland Terminal and will be accessible to customers utilizing our significant network of pipelines, we continue to have discussions on this project. As it gets closer to FID, we will provide more specifics. Now, turning to our Mariner East system. Since placing the initial capacity of ME2 into service at the end of 2018, NGL flows from the system have continued to ramp up as expected. As a reminder, in October, we completed modifications to ME1 and Marcus Hook to enhance the reliability of the system and allow for improved flows through the facility. These modifications allowed us to bring additional ethane volumes onto the system during the fourth quarter as expected.
At the beginning of this year, we were pleased to reach an agreement with the DEP that will allow us to complete the construction projects we have underway in Pennsylvania. Looking ahead, we are anxiously awaiting completion of the next phase of the project, which is now expected to be in service in late 2020, with the final phase completed in the first quarter of 2021. In the meantime, we are excited for the next tranche of volume ramp-ups on the Mariner East system, which will occur this spring. In addition, expansion efforts at Marcus Hook are underway as it provides customers with the most efficient way to reach the best markets for their product. This expansion will provide approximately 50,000 b p d of incremental NGL throughput capacity at the terminal by the end of 2020, accommodating volume growth from Mariner East.
We are also working to secure new third-party commitments to bring additional volumes to Marcus Hook. As for the Lone Star assets, as I mentioned, Frac VII is now in service, and our entire Mont Belvieu fractionation complex is expected to be at full utilization in the next 30 days. In addition, Frac VIII remains on schedule to be in service in the second quarter of 2021. Both fracs will be 150,000 b p d, and upon completion of Frac VIII, our total fractionation capacity at Mont Belvieu will be over 1 million barrels per day. To keep up with our growing frac capacity, our 24 in, 352 mi Lone Star Express expansion will add over 400,000 b p d of NGL pipeline capacity from the Permian Basin to the Lone Star Express 30 in pipeline south of Fort Worth, Texas.
We continue to expect it to be in service in the fourth quarter of 2020. We also continue to further develop our storage capabilities at Mont Belvieu. On our 235,000 bpd LPG expansion project at Nederland, construction is underway and progressing well. This expansion will further integrate our Mont Belvieu assets with our Nederland assets to expand our LPG export capabilities and is expected to be in service in the fourth quarter of 2020. The conversion of the White Cliffs Pipeline from crude to NGL service is complete, and volumes on this pipe, which runs from Platteville, Colorado, to Cushing, Oklahoma, began flowing in December of 2019. We expect volumes to continue to ramp up on this pipeline. On our Orbit joint venture with Satellite Petrochemical, for which we are constructing a new ethane export terminal on the U.S. Gulf Coast to provide ethane to Satellite.
Construction continues to progress as scheduled. We continue to expect the project to be ready for commercial service in the fourth quarter of this year. Turning to our processing plants in West Texas. Our 200 million cubic foot per day Arrowhead III processing plant, which went into service in early July, operated at near capacity for the fourth quarter. In addition, Our 200 million cubic foot per day Panther II processing plant in the Permian Basin was placed into full commercial services in January of 2020, and we expect it to be full by mid-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 fourth quarter results. ET's consolidated adjusted EBITDA was up 5% to $2.8 billion compared to $2.7 billion for the fourth quarter of 2018.
This is primarily due to another quarter of record operating performance from our NGL and Refined Product segment, as well as growth in the Crude Oil segment. ET DCF attributable to the partners as adjusted was $1.5 billion for the fourth quarter, up $30 million compared to the same period last year, primarily due to the increase in adjusted EBITDA. Distribution coverage for the fourth quarter was 1.88x . In January, Energy Transfer announced a distribution of $0.305 / common unit for the fourth quarter, or $1.22 / common unit on an annualized basis. This distribution is flat compared to the third quarter of 2019 and was paid today to unit holders of record as of the close of business on February the 7th. Turning to our results by segment and starting with the NGL and Refined Product segment, which had another record quarter.
Adjusted EBITDA increased to 30% to $743 million, compared to $569 million for the same period last year. The increase was due to record frac volumes, as well as increased NGL transportation volumes and terminal throughput. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.3 million barrels per day compared to 1.1 million barrels per day for the same period last year, mainly due to higher volumes on our Northeast assets related to the startup of ME2 pipeline in the fourth quarter of 2018, as well as increased volumes on our pipelines out of the Permian Basin and North Texas regions. Fourth quarter average fractionated volumes increased to 734,000 b p d, compared to 594,000 b p d last year. For our crude oil segment, adjusted EBITDA increased to $715 million compared to $636 million for the same period last year.
The increase was driven by a favorable inventory valuation adjustment. Crude transportation volumes increased to a record 4.7 million barrels per day compared to approximately 4.3 million barrels per day for the same period last year, primarily due to volume growth in the Bakken, as well as an increase in the barrels through our Bayou Bridge Pipeline and on our existing Texas pipelines. During the fourth quarter, we were fully utilizing the 570,000 b p d capacity on the Bakken Pipeline. For the midstream segment, adjusted EBITDA was $397 million compared to $402 million for the fourth quarter of 2018. Higher midstream throughput volumes were more than offset by lower NGL and gas prices, which impacted results by $29 million. Gathered gas volumes reached a record 14 million MMBtus per day, compared to 12.8 million MMBtus per day for the same period last year.
This increase was due to growth on the Ohio River System in the Northeast and higher volumes at the ArkLaTex, Permian, South Texas, and North Texas regions. Moving to the interstate segment, adjusted EBITDA was $434 million compared to $479 million for the fourth quarter of 2018. This was primarily the result of higher ad valorem taxes from placing the final portions of Rover into service and lower adjusted EBITDA from unconsolidated affiliates. Transportation volumes were 11.6 million MMBtus per day compared to 11.1 million MMBtus per day for the same period last year, due to the addition of new contracts out of the Haynesville Shale on the Tiger Pipeline and higher volumes from the Rover Pipeline. In our intrastate segment, adjusted EBITDA decreased to $222 million compared to $306 million in the fourth quarter of last year.
This was primarily due to lower revenues from pipeline optimization activities, which were partially offset by increased transport fees from new contracts across our Texas intrastate pipes, as well as the ramp-up of Red Bluff Express. Reported transport volumes increased primarily due to the higher utilization of our Texas pipelines, as well as the ramp-up of volumes on Red Bluff Express Phase 2. Let's look at the CapEx update. For the year ended December 31st, 2019, Energy Transfer spent $4.3 billion on organic growth projects, primarily in the NGL and refined products and midstream segments. This is excluding SUN and USAC CapEx. As I mentioned earlier, for the full year 2020, we expect to spend $3.9 billion-$4.1 billion, primarily in our NGL, refined products, and midstream segment, including $300 million of expenditures related to SemGroup.
Looking briefly at our liquidity position as of December 31st, 2019, total available liquidity under our revolving credit facilities were approximately $1.7 billion, and our leverage ratio was 3.96 x per the credit facility. In January 2020, we completed a registered offering of $4.5 billion of senior notes, as well as a public offering of $500 million and $1.1 billion of Series F and Series G fixed-rate reset cumulative redeemable perpetual preferred units, respectively. We used the aggregate proceeds from both offerings to repay certain outstanding indebtedness, including prepayment of certain senior notes and for general partnership purposes. We continue to target a rating agency leverage ratio of 4x - 4.5x . Before opening the call up to your questions today, I want to reiterate that we are very pleased to have delivered another solid quarter and overall, a record year here at Energy Transfer.
Looking ahead to 2020, we expect our fully integrated assets and predominantly fee-based cash flows to help insulate us from the weaker macro environment. We also expect our business to continue to generate a significant amount of excess cash flow, which will help fund our backlog of growth projects in a credit-friendly manner and allow us to further organically strengthen our balance sheet. The addition of the SemGroup assets, which significantly strengthens our crude oil and liquids capabilities and enhances our connectivity and footprint, as well as the ramp-up of growth projects, is expected to drive near and long-term value and offset headwinds from narrowing spreads and contract renewals. We remain disciplined in our approach to new capital projects, while safety and project execution continue to be among our primary focuses. Operator, we're ready to open the line up for questions.
Thank you. At this time, we will be conducting a question and answer session. As a reminder, we ask that you limit yourself to one main question and one follow-up. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two 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, as we poll for questions. Our first question comes to the line of Shneur Gershuni with UBS. Please state your question.
Hi, good afternoon, everyone. Before I jump into my two questions, Tom, can you just clarify that you said the long-term CapEx run rate is now $2 billion-$2.5 billion, down from $3 billion-$4 billion that you'd mentioned previously?
Yeah. Shneur, obviously, as you know, there's been a lot of discussion. This is probably one of the main talking points in a lot of the investor conferences, et cetera. As we just continue to evaluate it, and Mackie's here also can chime in. As we looked out, basically what we're saying is that $2 billion - $2.5 billion . I think we've been also very open about the fact that when you really look out at approved projects starting from 2021 on, that number's at $1.8 billion. Is that what you were looking for? Just clarification on that.
Yeah, I was just looking for the clarification.
Okay.
In terms of the two questions that I had, maybe to start off, Kelcy and Mackie, just wondering if you had made any progress on the recontracting of the Texas crude pipeline assets. I noticed there was a modest step down in rates, but higher contracted volume activity. Is that sort of reflective of the ongoing efforts to recontract that system?
This is Mackie. That's a high priority right now for our partnership. We kind of reorganized our crude team, led by Jim Malott, and there's a tremendous amount of time spent right now. We are a little bit different than our competitors in that now we have Houston, we have Nederland. As Tom talked about in the opening statements, we have all the refineries.
We're developing a VLCC project, so we're not in a panic to fill it, because what we're offering, of course, is from the wellhead out in West Texas or Cushing or Bakken and delivering it all the way to wherever they want it, to a market or to the export markets or to our VLCC project. Yes, we are in the process of negotiating. We're optimistic that we'll roll over and extend a substantial amount over the next six to nine months, and then long term, we expect a lot of those volumes to support our VLCC project.
No, that makes a lot of sense. Maybe as a follow-up question, Tom, with the recent financings that were completed in January, I realize it was a refinancing of the SemGroup related debt. One component that you noted, or two components I should say, included a pref. Typically you get equity credit for that or different levels of equity credit for that from the agencies. Does this now get you a lot closer to the leverage targets that the rating agencies are actually looking for or that they've shared with you? Was the equity credit part of the rationale in terms of using the pref as well as just a financing?
Yes. That is the short answer is absolutely. I think when you look at the retained cash flow, meaning the DCF above the distributions for the year, you'll see that that's a little over $3 billion, right at $3.1 billion. When you really add in these perpetual preferreds, obviously we've been trying to do everything in a very credit friendly manner in order to be able to achieve those accelerated de-leveraging. You can see that nearly $800 million added to that $3.1 billion gets you to $3.9 billion. Basically, we were able to fund the growth. When you look out at the guidance we've given for this year, you can say that we're funding it with no debt. No common equity and no debt.
All right, perfect. Thank you very much. Appreciate the call today.
Our next question comes to the line of Pearce Hammond with Simmons Energy. Please state your question.
Good afternoon. Thanks for taking my questions. My first is, what are your latest thoughts on a C-corp conversion or an up-C conversion?
This is Tom Long again. We have, I think, continued to talk about this, and once again, I know at a lot of the conferences, et cetera, we say that it's on the radar screen, and we continue to evaluate it. As we look out and we look at this market, we are getting a lot of feedback. We're hearing from a lot of our investors to have the option of a 1099 currency. In other words, a C-corp currency is something that we are hearing is appealing. We're going to continue to evaluate that. It is something that we think will be very beneficial.
Do you have a timeline that you're kind of roughly thinking on this evaluation?
No, in answer to your question, to give you the short answer of it, but I will tell you that it is something that we are, once again, evaluating as we look out through 2020 here.
Okay. Thank you, Tom. The follow-up is on the $2 billion-$2.5 billion of growth CapEx for 2021 and beyond. How much of that is to do with the higher return thresholds, or does it have a lot to do with just there's less projects to do in the industry as the production growth rate has slowed down for the U.S. E&Ps, more capital discipline, et cetera? Is it a combination of those two or more on just higher return thresholds?
This is Mackie. It's a combination. Tom talked about in opening statements all the projects that we brought on last year. Those projects are going to be ramping up throughout this year. We've got all these NGL projects coming on. We're in the mode of growing as fast as we can. We've set a threshold of 18%, probably even north of that, because our focus right now is filling up the assets that we have.
More importantly, as contracts terminate over the next three, four, five years on fracs and on processing plants that were built four or five years ago, we're really focusing on filling up those projects ahead of new projects. It doesn't mean that if a project jumps out and it's synergistic with our other assets, and it meets the rate of return threshold, that we won't spend more capital. It's certainly not something we're focused on right now.
Thank you, Mackie.
Our next question comes to the line of Colton Bean with Tudor, Pickering, Holt. Please state your question.
Good afternoon. Just to follow up on the commercial announcement from this afternoon, could you characterize what the current business contribution is from that counterparty, whether it be the Permian or the Eagle Ford?
Yeah, I can. Let me elaborate a little bit because it kind of goes to the same theme we're talking about. We couldn't be more excited about this type of structure that we've negotiated. It is anonymous, but it is a large player. For example, they had contracts that roll off in the next three or four years. We now have extended those out 10 years - 15 years. More importantly, what we've done is it increases the volume from around 300,000 a day to tiering up to up over 800,000 a day. In addition to that, the liquids are around 20,000 or 25,000 barrels a day. They will grow to in excess of 100,000 barrels a day.
Yes, we've taken some short-term pain on some discounts for the next couple of years from the existing deal that we had, but we couldn't be more excited how this is going to fill in our assets as contracts roll off. What it gives us the liberty to do is, as contracts roll off, we'll have the ability to either renegotiate at rates that work, and we will expand if we do, or we'll let those contracts roll off, and contracts like this will fill in the place and keep those assets full. We're very excited about that announcement.
Got it. Mackie, just on the up to 100,000 barrels a day of liquids, does that involve incremental processing, or is that coming from third-party plants?
It's approximately between 250,000 and 300,000 today. It'll grow to approximately or in excess of 800,000 Mcf a day. On the liquid side, it's approximately 25,000 barrels a day T&F, and it'll grow to over 100,000 barrels a day over the next two or three years.
Okay. To realize that 100,000 barrels a day, is that processing that you guys would be building out kind of full value chain, or is that-
No.
-mostly just on the T&F side?
Yeah, I'm sorry. I didn't answer your question. I didn't understand it. It's built out. We're utilizing existing processing capacity, existing liquid NGL transport capacity, and frac capacity. We're not adding any capital. We are adding some capital out in the field to gather this gas to our facilities, but this is a very low capital amendment and extension.
Got it. That's very helpful. Just to follow up on some of the earlier comments on NGL services, it looks like there was a decent step down quarter-on-quarter in terminal services. Can you all frame what you're seeing from the Mariner system maybe year-to-date, and whether the compression in global spreads has had any impact on the marketing business?
Yeah, this is Mackie again. If you focus on Marcus Hook, yes, the terminal volumes did decline over that quarter. The reason being is we had kind of almost historical prices for propane and of course butane blending into gasoline. There was a large demand in the Mid-continent. A lot of the barrels were leaving Western Pennsylvania and heading West. Even in northern New York and the Northeast, the price just skyrocketed.
A lot of the barrels that typically show up at Marcus Hook didn't show up for that quarter. Those barrels are coming back. A lot of the barrels that move through our lines, the Mariner system, are demand charged. Even though the volumes are down, we're still receiving revenue. One other point is, with PES, it has impacted our movements out of Marcus Hook and into Marcus Hook and other terminal assets that we have in the Northeast. Our teams are already looking at ways, and we're already filling those gaps with new deals and new long-term arrangements.
Got it. That's helpful. Appreciate the time.
Our next question comes to the line of Michael Lapides with Goldman Sachs. Please state your question.
Hey, guys. A couple of questions, actually. Can you talk, in the quarter, I think your release referenced that Mariner East 2 contributed $77 million. How should we think about what a kind of a normal quarterly run rate for Mariner East 2 is? Is that $77 million that normal run rate? Is it something that's a little bit higher that'll come in the first quarter of this year? How should we think about what the adder for 2X would be? Something similar to 2 or slightly different just due to the different size and capacity of the pipe?
Yeah. I think, we may elaborate a little bit, I think right now we won't get into those details to that degree. As we spoke earlier, we are very optimistic that by the end of the year, if not earlier, the next significant phase of Mariner will be completed. Once that is completed, we will already have committed volumes to step in with demand charges, both through our pipe and through Marcus Hook. Once we complete Mariner and add additional volumes, we'll see a substantial increase in revenue.
Got it. Just a question on Satellite. Your counterparty in China has made extremely good progress in the construction effort there, may even be on time, if not a tad bit early. Where are you all in the process of having conversations with them about incremental potential export capacity and whether or not they need, and if so, when?
Well, we say it every time, we couldn't be more excited about that project. It's a great partner with Satellite, just an outstanding Chinese company. They do what they say they're going to do. They're moving forward as we are. We're on track to be complete and loading ships by the fourth quarter. We haven't really had, to my knowledge, a lot of dialogue about expanding with them out of Nederland. Of course, we're in many conversations with expanding our ethane export out of Nederland with other customers. We certainly would accommodate very quickly any excess or any additional volumes that they would be interested in signing up for. Right now, I think they're focused on getting their crackers built and loading ships, hopefully, by the end of the year. We're real excited about that project coming to completion.
Got it. Thanks, guys. Much appreciated.
Our next question comes to the line of Michael Blum with Wells Fargo. Please state your question.
Thanks. Hey, everybody. First question is just on the Bakken Pipeline capacity expansion. You said the initial phase will be on in early 2021. Do you have a sense of how much capacity you'll have at that point?
Michael, as you can imagine, we don't know yet. We are still in the middle of an open season. Things are moving along very well. We've secured all the midpoint pump station sites. We've met with all the state and county agencies, and we filed all the required filings with them. We're working with several states to finalize the approvals that we need and also other interested third parties. In fact, we even received today approval from the North Dakota to amend the certificate to go to the 1.1 million barrels. We are designing and are seeking approval and will obtain approval for up to 1.1 million barrels to date. We don't know if we're going to reach that in this open season, but what we do know is there's a tremendous amount of interest.
We're by far the best option with the most optionality going to the Midcontinent Oil coming all the way down the Gulf Coast and hitting the St. James, et cetera, et cetera. Nothing compares to what we can do. We're confident that through time, we'll get to 1.1 million barrels over the next four or five years. It remains to be seen where we kind of level out here at the end of this open season.
Okay, great. Just wanted to ask on Rover, and I guess in general, the Northeast. Are you having any of your shipper customers approach you for short-term relief and those comments you made earlier about short-term relief in exchange for long-term contracts? Is anything happening up in the Northeast on that front?
Yes. We do have some of those inquiries and an extension similar to what I described in the Permian Basin. We also execute an extension and a better NPV returns for us with a customer. That's part of this impact we have over the next few years that's embedded in our numbers.
Great. Thank you.
Our next question comes to the line of Jeremy Tonet with JP Morgan. Please state your question.
Good afternoon. Maybe part of the answer for my first question picks up on that last point there. I'm just looking at 4Q 2019 EBITDA of $2.8 billion, and if I annualize that, it seems like it puts you right in the middle of the guide next year. Arguably, I think in 4Q 2019, some of the spreads had already kind of tightened, so there wasn't necessarily as much of a benefit there. I was just wondering, what other, I guess, headwinds or elements of conservatism built into the guide next year? Because with new projects coming online and the full year benefit of some of the things from this year, including the SemGroup acquisition, it seems like you have some nice tailwinds built in there.
Yeah. Listen, this is Tom Long. Jeremy, as we looked out at 2020, like I said in my prepared remarks, it was really two components. It's the contract renewal rates that we're looking at in addition to the spreads. We're happy to maybe talk to you in further detail if you'd like to kind of drill down further. I would say those are the two headwinds, and they're probably about equal in amount or so. That's in addition to those spreads. I'm not trying to say that we don't still look out at 2020 and still see spreads.
At the same time, they're not going to be at the level that we did get to enjoy through 2019. The other thing I think that is worth noting is that you did see some of the hedge benefit in the fourth quarter. We did break that out even in the press release a little bit that we had where spreads were net of the hedges. Keep that in mind, too, that we did see some benefit in the fourth quarter of 2019 for that. As we look out at 2020, you don't necessarily get to enjoy as much of that either.
Got it. Just want to direct one question towards Kelcy, if I could. It seems like the market kind of wants to pull ET in a lot of different directions, be it looking for growth, looking for improving competitive positioning, looking for stock appreciation. I guess I was just wondering if you could provide some comments as far as how you think what are the top priorities or top focus when you're thinking about how to run ET best?
Well, pipelines are really interesting. If you're not spending money on those assets, then you're deteriorating, you're eroding. You can't just stop. Energy Transfer will always pursue, as Mackie just said, high rate of return projects. We're blessed right now to have more of those than we really want to take on. We're going to continue to do that. We will continue. I know the market doesn't like this, but it's just reality. We'll continue to look at M&A. We always look at M&A. Unfortunately, the math doesn't work on virtually anything right now. SemGroup was an unusual circumstance. We'll continue to do that. We're very committed to the rating agencies to get our credit metrics very comfortably in a spot that we've been guided to. We will get that done. We're well on our way.
Tom Long and team, they're doing a fantastic job. Finally, I will tell you, we'll be very defensive. This is a market where right now we don't have to be very defensive because nobody's doing anything. We will continue to focus on that and protect our assets, not allow competition to encroach on our fringes, and therefore erode our margins. We're going to keep doing what we do. We're going to probably, I'll be a little bit more definitive than Tom was. We're probably going to offer a C-corp alternative to our unit holders, I think that if we do that, it'll happen this year. I think that's part of the plan also.
That's helpful. Thank you for taking my question.
Thank you.
Our next question comes from the line of Jean Ann Salisbury with AllianceBernstein . Please state your question.
Hi. You have mentioned before that in 2020 fixed fee contracts on Oasis start, which would materially reduce your exposure to Waha basis. Can you give any updated information around your remaining exposure going forward?
Sure. This is Mackie again. It's exposure, golly, it's fantastic exposure. We probably have a half a BCF today that exposed at markets at spreads that are kind of $1.50. I think prompt month is even maybe close to $2. However, we also stuck to our strategy, and we do have some large contracts, 10-year contracts that are coming on later this year. October, November is one of them, and the other one's the first part of 2021.
The spreads still probably wide, it's the right thing to do to hedge those out and get a good healthy rate long term and not take the risk of the collapse. The team has done very well, I believe, on how we've kind of strategized and how we sell that space. We're going to benefit to a large degree on those spreads this year. As time goes on and more capacity is built with more risk of the spreads coming in, we will have more of that sold under long-term agreements.
That's really helpful. Thank you. Thank you for the commentary around the focus on contract extensions. One of your peers recently disclosed a range of crude contract rates that they got for a 10-year extension. Would you be willing to give a range of what you see as sort of the long-term going rate for crude pipeline capacity? I think it would give investors some confidence that it's not going to cash cost.
The most we can possibly get, and I really mean that sincerely. There's customers that will pay a certain rate to go from, for example, from Midland to Houston, and then there's customers that say, "We want the option to go to Houston, Midland into St. James to Maurepas, and we also want a bunch of storage and export rights." It probably wouldn't be wise to us to kind of give a range on a call like this where it's so public and many of our competitors. It's a pretty wide range, and we'll continue to pursue those and achieve the highest price we can for our service.
Fair enough. Thank you.
Our final question comes from the line of Keith Stanley with Wolfe Research. Please state your question.
Hi. Thanks. Tom, what was leverage at year-end the way you or I guess the way the rating agencies would see it versus the 4x -4.5x target?
Well, listen, that varies so much between the agencies. We're still staying in that probably slightly above that 4.5x, you know the 5x or so. Once again, with the joint ventures, then the consolidated with both SUN and USAC, et cetera, as you can see, that varies a bit. The best I can do is kind of give you that range of where we are.
Okay. When you're looking at 2020, if EBITDA is flat this year, obviously debt's not increasing because you have it funded now, but it just feels like asset sales are the best way to delever, kind of, especially on a more near-term timeframe and get to your target. How do you think about asset sales right now given the outlook for 2020 and desire for more financial flexibility? I guess also taking into account that the asset sale market's probably softened a bit here, just how you're weighing that overall.
Listen, we think we've done a very good job of the asset sales that we've done. I think we got way out ahead of it. If you looked at it currently around your questions here right now, I think we've been pretty open in what we talked about as far as the compression from that standpoint. I can't really take you any further than that as far as anything goes on that front. Clearly, that's not anything you would talk about ahead of time. At the same time, we very much like our assets with where we currently stand. Like I said, we'll just continue to as we go through the year to be diligent on that front, but to be very smart.
Okay. Thank you.
Ladies and gentlemen, this does conclude today's question and answer session, and I would like to turn the call back over to Mr. Tom Long for any closing remarks.
All right. Once again, thank all of you for joining today. We really do appreciate your time today and your interest. We look forward to the follow-up calls that any of you may have. Thank you.
This concludes today's teleconference. You may now disconnect your lines at this time. Thank you for your participation, and have a wonderful day.