Greetings. Welcome to Energy Transfer Fourth Quarter Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. Please note, this conference is being recorded. I will now turn the conference over to your host, Tom Long. You may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer fourth quarter 2020 earnings call, and thank you for joining us today. I’m also joined today by Mackie McCrea 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 21-E of the Securities 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 Annual Report or Form 10-K for the year ended December 31, 2020, which we expect to be filed in the next several days. 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'll start with our recent announcement. We were excited to announce that we have entered into a definitive merger agreement to acquire Enable Midstream Partners in a credit accretive all-equity transaction valued at $7.2 billion. The transaction is expected to be immediately accretive to free cash flow post distributions, have a positive impact on our credit metrics and add significant fee-based cash flows from fixed fee contracts. Under the terms of the merger agreement, Enable unitholders will receive 0.8595 ET common units for each Enable unit, an exchange ratio representing an at-the-market transaction based on the 10-day VWAP of ET and Enable common units on February 12, 2021. In addition, each outstanding Enable’s Series A preferred unit will be exchanged for 0.0265 Series G preferred units of Energy Transfer. These assets are a great fit for our system and will be very complementary. We expect this consolidation to provide increased scale in the Mid-Continent, Ark-La-Tex regions and improved connectivity for our natural gas and NGL transportation businesses. Through this acquisition, we will be adding substantial gathering and processing assets in the Anadarko Basin, which gives us the opportunity to enhance our ability to provide an integrated end-to-end midstream solution utilizing our downstream fractionation and export platform on the Gulf Coast. And the addition of Enable’s crude gathering assets in the Bakken will help ensure wellhead-to-market connectivity via our Bakken pipeline system. Enable’s transportation and storage assets are also expected to enhance our access to core markets with consistent sources of demand and bolster our portfolio with the addition of long-term firm contracts anchored by large investment-grade customers. Pro forma for the acquisition, we continue to expect to generate approximately 95% fee-based cash flows. In addition, we expect the combined company to generate more than $100 million of annual run rate cost and efficiency synergies, excluding potential financial and commercial synergies. The combination of Energy Transfer’s and Enable’s complementary assets will allow the combined company to leverage its extensive infrastructure to pursue additional commercial opportunities and achieve cost savings while enhancing our ability to serve customers. The transaction has been approved by the Board of Directors of Energy Transfer and Enable and Enable’s two largest unitholders, OGE Energy Corp. and CenterPoint Energy Inc., have entered into support agreements that require them to provide their consent to the transaction upon SEC effectiveness of the Form S4 registration statement for this transaction. As these two unitholders own approximately 79% of the outstanding common units of Enable, no additional unitholder votes will be necessary upon receipt of these consents. The transaction is expected to close in mid-2021, subject to HSR and other customary closing conditions. We view this acquisition as a strategic opportunity to expand our scale and midstream connectivity, while remaining consistent with our goals of improving our financial position through deleveraging. Now I just want to briefly touch upon the unprecedented winter weather conditions we're currently seeing across the country. Just like the majority of our peers, we're experiencing impacts to our operations related to the extremely cold temperatures. But we believe our operations team is second to none, and their efforts over the last few days have been remarkable. They are in constant communication with our commercial teams, and are trying to do what is best for our customers, particularly those serving human needs, customers and electric generation facilities. The situation is changing constantly. And our team is addressing these challenges on an hour-by-hour basis as best as possible. Next, turning to a few of our fourth quarter and full-year 2020 highlights. For the full-year 2020, we generated adjusted EBITDA of $10.53 billion, which came in just above the top-end of our guidance range. DCF attributable to the partners of ET, as adjusted, was $5.74 billion, which resulted in excess cash flow after distributions of approximately $3.27 billion. On an incurred basis, we had excess DCF of approximately $215 million after distributions of $2.47 billion and growth capital of approximately $3.05 billion. As we discussed on previous calls during 2020, we implemented cost reduction measures throughout our corporate offices and field operations. For full-year 2020, we achieved G&A and OpEx savings of over $500 million. We expect about $300 million to $350 million of this to be reoccurring in 2021. Operationally, we moved a record number of NGLs through our pipelines for full-year 2020, primarily driven by our Mariner East and Texas NGL pipeline systems. And our fractionation volumes also reached a new high during 2020 due to additional ramp up of volumes on Frac VII, which went into service in February of 2020. During the fourth quarter of 2020, we completed construction of our 50,000 barrel per day LPG expansion at the Marcus Hook terminal. Also during the fourth quarter, we were excited to complete the majority of our LPG expansions at our Nederland export terminal. And in January 2021, we announced that we loaded our first very large ethane carrier with 911,000 barrels under our orbit joint venture with Satellite. Briefly taking a look at guidance for 2021. Our adjusted EBITDA is expected to be $10.6 billion to $11 billion. Compared to 2020, we expect to see strong growth from our NGL segment as increased export activities drive higher demand across our NGL system and we expect a positive contribution from NGL and gas prices. This growth will be partially offset by some headwinds related to crude spreads as well as a decrease from certain contract expirations. This guidance is for the existing Energy Transfer business excluding any contribution from Enable. We expect to provide pro forma financial information in the S4 when it is filed in the next few weeks. And for growth capital, we now expect 2021 growth capital expenditures to be approximately $1.45 million. This number includes approximately $250 million of 2020 plan capital that has been deferred into 2021. When accounting for this, our updated 2021 capital guidance represents a further reduction of approximately $100 million to what had been previously communicated. We continue to focus on discipline in regards to all spending and are committed to aligning capital outlay with customer needs. Our 2021 growth capital expenditures are primarily made up of several projects within our NGL and refined products, crude and midstream segments, additional modular marination storage, BG facilities at Nederland and our Cushing to Nederland project. In addition to expanding our presence in the northeast and on the Gulf Coast, this spend will improve our opportunities around our existing assets, further strengthening our footprint in key basins. We continue to expect to spend approximately 500 to $700 million per year in 2022 and 2023. For 2021, we continue to expect to generate a significant amount of excess cash flow. This will be directly used to pay down debt balances and maturities as 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 unitholders in the form of unit buybacks and/or distribution increases with the mix dependent upon our analysis of market conditions at the time. I'll now walk through recent developments on our major growth projects and we'll start with DAPL. As you may recall, the District Court ruled last March that the Army Corps needed to prepare an environmental impact statement for the Dakota Access Pipeline, and then ruled in August that the easement that Dakota Access received from the Army Corps at Lake Oahe be vacated and the pipeline shut down. The Army Corps appealed both of these decisions. And in January, the DC Court of Appeals affirmed the decision requiring the Army Corps to prepare an EIS, but overturned the decision to shut down the pipeline. Separately, the District Court is considering a motion filed by the tribes for an injunction for the purpose of shutting down the pipeline. Briefing was completed on this motion in early January, but the District Court has not ruled on this motion. Following the DC Court of Appeals decision that I just referred to, the District Court ordered a status conference to discuss the injunction motion and the Army Corps position related to the vacated easement in light of the DC Court of Appeals decision. On February 9, the Army Corps requested that the status conference be postponed until April 9, and the District Court approved the motion. In the midst of these legal proceedings, the Army Corps initiated the EIS process in September of last year, and we expect that the EIS will be completed by the end of this year. The pipeline remains in service and like all of our assets will continue to operate safely and efficiently. We do not see a scenario where the pipeline will be shut down; we are still in America with Rule of Law. The Army Corps gave us guidance early on in the permit process, about the best locations to construct the pipeline to have the least impact on the environment. DAPL has been one of the most scrutinized, politicized, yet safest pipelines ever built in our country. It has been safely flowing for almost four years and is critical to this country for jobs, tax revenue, and for energy security and independence. Next, the TED Collins link will significantly increase the utilization of existing assets by repurposing our Eagle Bond pipeline that was previously bringing barrels out of the Permian, while providing market connectivity between our Nederland and Houston terminals. It will ultimately allow us to transport up to 275,000 barrels of crude oil from West Texas and Nederland to our Houston terminal and is expected to be in service in the fourth quarter of 2021. Our Cushing to Nederland project will provide the ability to move crude barrels from our White Cliffs pipeline and Cushing storage assets through our existing Permian Express 1 pipeline system, and third-party pipelines to our Nederland terminal on the Gulf Coast. Upon completion in the second quarter of 2021, we will be able to transport between 65,000 and 120,000 barrels per day of crude oil from the DJ Basin in the Cushing area to Nederland. Now let's turn to our Mariner system. Fourth quarter 2020 NGL volumes through the Mariner East pipeline system increased more than 30% over the fourth quarter of 2019. Utilization of our Mariner pipelines and our Marcus Hook Terminal remained strong in the fourth quarter across all products. The system continues to demonstrate flexible optionality for shippers including the ability to handle ethane spot cargoes, as well as provide multiple local market connections for ethane, propane, and butane. As I mentioned earlier on the call in December 2020, we commissioned 180 miles of ME2X from Delmont, Pennsylvania to Cornwall, Pennsylvania and also placed our 50,000 barrels per day LPG expansion at the Marcus Hook terminal into service. And we now expect the next significant phase of the Mariner East projects to be in service in the second quarter of 2021. The completion of the next phase of Mariner East will also give us the ability to initiate service on Pennsylvania access, which will bring refined products from the Midwest supply regions through our Allegheny Access pipeline system into Pennsylvania into markets in the Northeast. This project will require minimal capital, which is already included in our budget, and we expect through time that it will add significant revenue and synergies with our existing refined products, pipelines, and terminal assets. It is also expected to be in service in the second quarter of 2021. The final phase of the Mariner East pipeline is expected to be completed in the third quarter of 2021. We also anticipate transporting natural gasoline through Mariner East beginning early in the second quarter of 2021. The Mariner system in conjunction with the Marcus Hook terminal continues to provide the most efficient transportation route for liquids in the Northeast, and provides customers the optimal way to reach the highest price markets for the product. As I mentioned earlier, during the fourth quarter, we completed expansions of our LPG facilities, along with the construction of a new 20-inch pipeline that directly links our fractionation and storage assets and Mont Belvieu, Texas, to our Nederland export terminals on the US Gulf Coast. The completion of these projects takes our LPG export capacity from the Gulf Coast to approximately 500,000 barrels per day for which we have significant demand. And finally, construction of our 180,000 barrels per day Orbit ethane export joint venture with Satellite Petrochemical was completed at the end of 2020. We loaded our first very large ethane carrier with 911,000 barrels under this joint venture in 2021. The Seri Everest, the world's largest VLEC, departed from Orbit's newly constructed export facilities at our Nederland terminal as the largest single shipment of ethane to date. We expect the next ship to arrive in Nederland for loading in March. With the completion of our LPG and Orbit expansions, we now have four separate NGL pipelines for ethane, propane, butane, and natural gasoline that connect our Mont Belvieu facilities to dedicated chilling storage and marine loading facilities at our Nederland terminal to support enormous international demand for NGL exports. In addition, the completion of these expansion projects at our Nederland terminal as well as our expansion at our Marcus Hook terminal brings our total NGL export capacity to just over 1 million barrels per day. Next, just an update on our environmental activities. Last week, we announced that we have created an alternative energy group to focus on pursuing alternative energy projects and reducing our environmental footprint in a manner that makes economic sense. Tom Mason will be heading up this group and in this role he will be coordinating various initiatives within the partnership focused on renewable energy projects, such as solar and wind farms, either as a power purchaser or in partnership with third-party developers, and will also look to develop renewable diesel and renewable natural gas opportunities. These potential projects could involve the utilization of existing pipelines through our extensive pipeline system, which consists of more than 90,000 miles of pipelines crossing 38 states. Today, nearly 20% of the electrical energy we purchase off the grid and generate from solar panels originates from renewables. In November, we announced that we had entered into our first-ever dedicated solar contract that will deliver 28 megawatts of low-cost clean power to energy transfer under a 15-year power purchase agreement. Also, we're in advanced discussions to support a significantly larger solar project with a long-term power purchase agreement. As we think about emission reductions, our patented dual drive compression technology offers the industry a compression solution that helps to reduce greenhouse gas emissions. In 2020, this technology allowed us to reduce scope one CO2 emissions by more than 630,000 tons. We have also implemented carbon capture sequestration at several of our existing trading and processing facilities that are already allowing us to sequester more than 85,000 metric tons of CO2 on an annual basis. We are also actively pursuing numerous other carbon capture and sequestration projects related to our gathering and processing facilities 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. Just touching briefly on our EHS metrics for 2020. Our total recordable incident rate or TRIR was a record low of 0.87 compared to 0.94 in 2019. And we worked over 17 million hours. We're extremely pleased with our team's ability to reduce this metric, which speaks to their efforts and strong focus on safety and environmental compliance, as well as the reliability of our assets. Now, let's take a closer look at our fourth quarter results. Consolidated adjusted EBITDA was $2.59 billion compared to $2.77 billion for the fourth quarter of 2019. This was primarily the result of volume growth on the Mariner system, the acquisition of new assets and lower operating expenses across all of our core operating segments, which were offset by decline in volumes in the crude and midstream segments as well as reduced optimization gains in the crude and NGL businesses. DCF attributable to the partners as adjusted was $1.36 billion for the fourth quarter compared to $1.51 billion for the fourth quarter of 2019. This is primarily due to the decrease in adjusted EBITDA. And on January 28, we announced a quarterly cash distribution of $15.25 per ET common unit, or $0.61 on an annualized basis. This distribution will be paid on February the 19th to unitholders of record as of the close of business on February the 8th. Now turning to our results by segment, we'll start with NGL and refined products. Adjusted EBITDA was $703 million compared to $743 million for the same period last year. This decrease was primarily due to lower optimization gains from the sale of NGL components at Mont Belvieu, as well as lower margins from butane and gasoline blending, which were partially offset by higher fee-based margins from our Mariner system and Nederland terminal. NGL transportation volumes on our wholly-owned and joint venture pipelines increased to 1.4 million barrels per day compared to 1.3 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 throughput on our Texas NGL pipeline system as a result of higher export volumes feeding into our Nederland terminal from the initiation of service on our propane export pipeline in the fourth quarter of 2020. On our fractionators, average fractionated volumes increased to 825,000 barrels per day compared to 734,000 barrels per day for the fourth quarter of 2019. For the crude oil segment, adjusted EBITDA was $517 million, compared to $676 million for the same period last year. This was primarily due to lower volumes on the backend in Texas crude pipelines as a result of lower production and reduced demand due to COVID-19 lower rates on our Texas crude pipelines, as well as a decrease in our crude oil acquisition and marketing businesses, primarily related to less favorable pricing conditions. For midstream, adjusted EBITDA was $390 million compared to $397 million for the fourth quarter of 2019. This was primarily due to volume declines in lower NGL pricing, which were partially offset by reduced expenses. Gathered gas volumes were 12.6 million MMBTUs per day compared to 14 million MMBTUs per day for the same period last year. Lower volumes in South Texas and in the Northeast were partially offset by volume growth in the Permian and Ark-La-Tex as well as the addition of assets acquired in 2019 in the Mid-continent and Panhandle region. In our interstate segment, adjusted EBITDA was $448 million compared to $434 million for the fourth quarter of 2019. This was primarily the result of reduced operating expenses, SG&A expenses, and increased margin from the Transwestern Panhandle and Rover Systems due to increased demand in firm transportation. These were partially offset by scheduled contract rates stepped down in January 2020 at our Lake Charles LNG facility, as well as contract expirations on Tiger. In our interstate segment, adjusted EBITDA was $233 million compared to $222 million in the fourth quarter of last year, primarily due to higher physical storage margins from withdrawals and higher realized gains from our hedging activities, as well as reduced operating expenses. For 2021, we expect to have less exposure to spreads as we have locked in additional volumes under long-term contracts with third parties. Let's look at CapEx, for the full year, December 31, 2020, Energy Transfer spent $3.05 billion on organic growth projects primarily in the NGL and refined products and midstream segments. This excludes SUN and USAC CapEx. And we currently expect our 2021 growth capital expenditures to be approximately $1.45 billion and growth capital in 2022 and 2023 to be between $500 million and $700 million per year. Looking briefly at our liquidity position. As of December 31, 2020, total available liquidity under our revolving credit facilities was approximately $2.79 billion. And our leverage ratio was 4.31 times for the credit facility. For 2021, we have debt maturities of $1.4 billion, which will be more than covered with our retained cash flow. In conclusion, we believe there is increasing value to have a strong existing asset base, and will continue to strategically enhance our footprint and improve our industry-leading franchise. Looking ahead, we are extremely excited about the acquisition of Enable, which will be credit accretive and provide meaningful incremental cash flows post distributions. In addition, these complementary assets will enhance our midstream infrastructure and provide increased connectivity throughout the Mid-continent and Gulf Coast. We're also very excited about our NGL projects that we brought online in the fourth quarter and in the first month of 2021. And believe we are well positioned to help meet increasing demand for NGL exports. We are focused on exercising capital discipline as we work to create more financial flexibility, generate additional excess cash flow, and lessen our cost of capital. And we remain committed to our investment-grade rating and accelerating our deleveraging by immediately using excess cash flow to pay down debt. We're also taking new steps to expand our efforts to develop alternative energy projects when they make economic sense and further our commitment to reducing our environmental impact. Energy Transfer’s best-in-class assets and extensive geographical footprint positions the partnership to respond to changing market conditions and for continued long-term success. Operator, please open the line up for our first question.

At this time, we will be conducting a question-and-answer session. One moment please, while we poll for questions. Our first question is from Jeremy Tonet with JPMorgan. Please proceed with your question.

Hi, good afternoon. I hope that everyone is well with weather and everything happening in Texas. Just wanted to get kind of a broader portfolio question out there regarding the higher commodity prices. It would seem to potentially induce greater producer activity. I was just wondering how your producer conversations might have been evolving recently on that front with higher commodity prices there? And then just wondering as well, the recent weather, do you see any kind of lingering impacts in the quarter just if you could walk through how you think that could be an offset there?

You bet, I can take that, Tom. Certainly, the last four or five days have hopefully opened up the reality of the necessity of natural gas for electric generation for our country and especially here in Texas and Oklahoma and surrounding states. Yes, commodity prices had continued to increase over the last two or three months, crude oil has continued to increase. We've got a higher demand, a lot of the vaccines happening across the country. But what this really does, what's happened over the last four or five days, I mean, if, for example, if you ask Oklahoma, would you guys wish you had more gas, because they can't run – they can’t generate enough electricity to – similar to Texas to provide the necessary electricity to run homes and for the LDCs to provide gas to their residential. So it's a tough situation. But we already had seen the corner kind of turning with some of our producers. Some of them have said things publicly, some of them haven't said it publicly how they're going to increase their spending in light of crude oil increases. And no doubt what's transpired over the last few days, we're going to see an increase in gas prices. We've been at kind of historical levels for the last number of years above the five-year average in storage, for example. And we don't know where it's going to end up when it does settle after all this, but it'll be hard to believe it's not going to be at a lower level; it's been a long time. So heaven forbid, if another cold front hits in a week or two, because there’s – storage is going to be running at very low levels. Hence, the value of oil and gas is going to do nothing but increase, we believe, we do believe this is going to help producers to go out and bring their ducks on and start bringing more rigs in like they've kind of been doing over the last four or five months. So as I start out saying, this has really opened my eyes, I think, of the country of the necessity of oil and gas and especially natural gas in this instance to provide fuel for our electric generation facilities throughout the country really.

Certainly highlights the value of hydrocarbons there, as you said. Maybe shifting gears a little bit. In the press release this morning, I think, ET had mentioned the $100 million of annual run rate cost and efficiency synergies. And talked about, I guess, connecting now the Anadarko footprint to the Gulf Coast – your Gulf Coast footprint there. I was just wondering if you could expand a lot more on the map. The synergies you see there on the map, it looks like it lines up nicely, but just hoping for some more color would be helpful? Thanks.

So – yes. Go ahead, Tom.

Yes, Jerry. Go ahead, Mackie. Go ahead.

Well, I was going to let you kind of talk about the $100 million of synergies. But if you're talking about just the commercial synergies, gosh, we haven't really even begun to evaluate and fully appreciate what we're going to recognize from this acquisition. It's an absolutely incredible acquisition at a very unique time when I just said the necessity for natural gas is going to grow not only in this country but around the world. And these assets are the most significant assets in the State of Oklahoma and throughout the Ark-La-Tex. They fit very well with our assets. And everybody knows there’s a large pipeline that brings rich gas down into the fourth basin that delivers into our processing plants and then feeds into our downstream pipelines. There's a lot of opportunities over in Western Oklahoma and Texas, Panhandle where we can create significant efficiency between these assets. There are large intrastate pipelines that feed across the State and into Bennington that connect into our interstate pipelines. And then we have significant synergies from Carthage and throughout Louisiana. We have some new opportunities with MRT and in new deliveries to the north. So, as I mentioned, we really haven't totally quantified from a commercial standpoint. What all is going to happen with this and all the benefits that we're going to see. But - and there's a lot from the commercial, I mean, I'm sorry from a competitive standpoint we won't really talk about, but we certainly will also have the ability to move natural gas liquids from the tailgate of a lot of these Enable plants into our NGL system to feed down to Mont Belvieu to keep our fracs for many years to come.

Exciting, exciting news for us.

Great. Thanks for that and wishing the best to all of you and your families.

You too.

And our next question is from Shneur Gershuni with UBS. Please proceed with your question.

Hi. Good afternoon, everyone. Glad to see you're all warm and well. Maybe just to clarify your response to Jeremy's question before I jump into my two. So the $100 million in synergies is cost-related and, Mackie, you're seeing incremental commercial revenue type opportunities that you haven't actually put on paper yet? Is that the correct answer?

That's correct.

Okay, perfect. Awesome. Just starting off with, with guidance here. I was wondering if I'm not sure if it's an accurate term question here. But if you can talk around – talk about the sensitivities around achieving potentially the high end of your guidance, is that really just driven based on commodity prices in spreads? Or is there some flex in your guidance volumetrically or elsewhere that would allow you to achieve the high end of your guidance?

Well, Tom, I can start from a commercial perspective and I've kind of alluded to that earlier. We did see volumes kind of struggle, especially in Eagle Ford and a few other areas, as we went through the fourth quarter of 2020. However, we started to see the light at the end of the tunnel, and we started to see rigs start moving in throughout last year. As we entered into 2021, there have been some public statements made, where producers have announced they're going to increase their capital budget, not a lot, but some. And then we've had conversations with a bunch of producers that are now anticipating spending more than what they've even made public. Of course, we can't share that. But anyway, there's a lot of optimism because of what's happening to the markets and the demand growing and the value of oil and gas increasing that we are very confident that drilling is going to pick up. In addition to that, we are excited about our NGL projects. We have a lot of that in our budget. However, we are going to be able to squeeze out even more volume out of both our Marcus Hook facility and out of Nederland. So we're very optimistic on being able to really capitalize and maximize our ability to export around the world out of those significant terminals. So we really see some upside there. And then we've also, of course, seen some upside just over the last four or five days, when you consider that everyone on this call recognizes how important fossil fuels are for this country in this world. But what's really important is to be able to get the fossil fuels to the market. And if there's one thing Energy Transfer does better than anybody, especially in Texas and really throughout the country is to move molecules from the source to where they need to go. And so we've been able to benefit over the last four or five days of being one of the major providers of transportation across the state from both West Texas and also from the Carthage area where large volumes can come in and out of those areas. And we're able to move those down to what we've really focused on. And that's getting gas to the human need customers. So a lot of the sales both on purchases that we're making and others are making on our system, and the sales that we're making out of our storage facilities and we have one of the most significant source facilities in the state, just north of Houston. And we've been maximizing our withdrawals and capitalizing on very strong commodity prices because we already had all that gas in the ground ready to come out in this type of situation. And it's really paid-off even though our state as well as much of the nation is struggling and a lot of people don't have electricity and gas; a lot of them do. And it's because of our ability to bring a lot of gas out of our storage facilities in other areas on our pipeline system and deliver them to all these power plants that are generating this electricity.

Thank you for the thorough answer there. And maybe a follow-up question with respect to the Enable transaction. I recognize that most of the rating agencies have opined on your current standing. You noted in your prepared remarks and in the slide deck that it's supposed to be leverage accretive. Just wondering on the margin if you can comment about the feedback from the agencies, does the larger size of Energy Transfer improve your standing with the agencies? Does the dilution of the potential DAPL outcome help you with the fact that you're going to have a higher regulated percentage of earnings? Just curious on how the transaction was perceived? Even if we can see specifically a change announced today, does it move the chains up the field at all? I'm just wondering if you can speculate about this.

Yes, we did have very good conversations with all three of them, I think you touched upon the fact that all three have put out little reports on this. And I think it's fair to say that it was slightly positive, I think the analogy you used, kind of moving the chains down the field a little bit. Clearly, all the stuff that Mackie just covered of how excited we are about the additional opportunities we're looking at, we were very conservative in how we really looked at this. We think that as we get in and bring more of the commercial teams over the fence, operation teams etc. And move further into this, that we're going to be able to get back with the agencies of possibly even improved type numbers. But right now, we feel like the $100 million was right down the middle of the fairway; likewise, we are looking for more but the agencies it was, I think, very good discussions with all three.

Perfect. Thank you very much. And definitely stay safe and stay warm in this weather.

Thank you.

You too.

Our next question is from Christine Cho with Barclays. Please proceed with your question.

Thank you. Good evening. Maybe if I could start-off with the Enable deal. Would you say that the deal has more commercial synergies on the gas side or the NGL side from a financial perspective? And you noted fractionation and exports in the press release is an opportunity. But could there also be NGL takeaway? And would there be like, what would be the timing? Would any of that be immediate or do you have to wait for third-party contracts?

This is Mackie again. I'll start with that, Tom. Well, there is certainly some confidentiality issues with statements we can make around contracts, of course, and all that kind of stuff. But I'll start with gas, there are significant gas opportunities there, as we've already talked about, just with how their pipelines feed into our pipelines, both upstream and downstream, where we can utilize plants up in the fourth base more efficiently in the pipelines more efficiently. So a lot of upside around the natural gas side and the gas gathering side. As far as the NGL side, more of the opportunities that we see or down the road a little bit as contracts roll-off. But as they do, we'll be able to connect the dots, so to speak, to where we can move those barrels down into our significant Lone Star system where we have a 30 inch that runs out of the fourth basin area all the way down Mont Belvieu. So we'll be able to bring significant volumes, not only from in the Enable cryos, but also from other cryos. We really see the NGL side more of a big benefit several years down the road, extending for many years after that. Whereas the natural gas gathering, processing, and the natural gas side is more immediate benefits and synergies that we see.

Okay, that's great. And then actually, if I can move on to DAPL, does that status conference hearing need to happen in order for the District Court to make a decision? I wasn't sure if the two were independent of each other or not. And how does it work at the Army Corps? If they need to tell the court what their action is going to be? Who necessarily decides it within the Army Corps? Is it the chief or is there someone else or is there some sort of committee? Any insight into that process would be helpful?

Yes, Tom Mason here. With respect to your first question, it's unclear whether the two are dependent on each other. The judge could rule on the injunction motion without having the status conference; I think he probably wants to wait until that conference or after for various reasons. So it's just a little bit hard to predict. But I would say that there’s a more likely chance he would wait until after that status conference, even some period after that. So he may not rule for a long time we still know. On the second question, it's clear as to who's making the decision. The Army Corps, I think we've been very professional throughout the last five years of our dealings with them. If left alone from political interference, I think we will continue to make good decisions as they proceed.

Okay, thank you.

Our next question is from Michael Blum from Wells Fargo. Please proceed with your question.

Thanks. Good evening everyone. Hope everyone's doing well. Maybe just to stay on Dakota Access and the Army Corps. Do you know if the Army Corps under the new administration is going to incorporate climate change analysis into the EIS? And if so, is that factored into your timeline that you provide it for when you think EIS gets completed?

This time Tom Mason again. We really don't know and obviously, the Biden administration has put out a deck of orders to talk about agencies evaluating climate change in the number of decision making. I don't know if this will affect the EIS process at all. It's too early to tell on that.

Okay, and then just have a quick question on the Enable transaction. Are you contemplating possibly rationalizing any processing capacity in the Mid-continent? It seems like there's a lot of excess capacity there. And then sort of related to that perhaps, with this transaction, do you see anything as non-core that you might look to monetize some assets?

Michael, this is Tom, I'll run with this. And Mackie, if you want to add something. As we went through this process, we saw these assets as actually very complimentary. So I can say that we have that mapping identified as far as divestitures, whether it be for or even identified as non-core as we say here right now.

Great, thank you.

Thank you.

Our next question is from Jean Ann Salisbury with Bernstein. Please proceed with your question.

Okay. I'm glad that you guys all have power. One on the Enable deal, is the Bakken crude gathering system already moving down DAPL or would those be new volumes for DAPL?

I don't know, I'm not 100% sure. All of that's moving us. I think the vast majority of it is, but I'm not sure if 100% of it is.

Okay, that makes sense. And then just wanted to dig a little bit more about some of the major assumptions in the 2021 guide. So I guess most importantly, are there any kind of numbers that you could give around what you're expecting for U.S. crude production growth or Permian crude production growth year-on-year to just kind of level set versus other people's guidance?

Yes, we're pretty conservative. When you look at kind of across the board on that right now, for example, the Permian crude is around 4.1 million-ish, maybe a little more than that. We don't expect it to get more than about 4.4 million barrels a day by the end of the year. But there's a lot of good things happening. For example, if you look at just a year ago, if you look at the floating crude around the world, there were about 90 million barrels. In July of last year, there was 230 million barrels, and now we're back down to about 90 million barrels. As we keep saying earlier on this call, we're very optimistic about the turnaround in market growth. So we do think that pricing will increase production. As far as total U.S. growth, I don't know. I don't really have an estimate on that. Other than probably a summer type growth where it might be a 2% or 3% type number.

Okay, that makes sense. And then just a couple of other assumptions in the 2021 guide. Is DAPL expansion in there?

Yes, DAPL is included. Absolutely.

And then last, DAPL expansion?

Yes.

Okay, great. And then last one is on have you received all of the Bakken crude MBC and flex payments from kind of earlier this year, or did some of those go into 2021 guidance?

No, none of those are rolled over. Yes, we will get on all those in 2020.

Next question is from Michael Lapides with Goldman Sachs. Please proceed with your question.

Hi, guys, actually, a couple of questions. First of all, on crude spreads are obviously de-minimis right now in a lot of different places. But just curious in the other businesses, especially given what's happening with gas over the last four or five days, where do you see potential dramatic changes relative to what you realized in 2020, in terms of optimization revenues, whether up or down?

Well, it’s Mackie again. As I mentioned earlier, because of the nature of our assets, and how we operate them and where they're located, especially our storage facilities, we feel very fortunate to be able to have gas in storage at a time when it's needed in a big way and to be able to come out at whatever the market prices are at that time. And unfortunately, from that standpoint, prices are really strong, they're kind of at historical levels, especially as you get up into Oklahoma and we've heard prices over $1,200 an MCF up there. But anyway, in Texas alone, our assets are doing exceptionally well. At a tough time we hate what's going on around the country in this state. But we're doing everything we possibly can to pull gas out of storage and deliver it to the power plants and the LDCs. And also to find gas, Waha or Carthage and bring as much as we can in off Tiger and other pipelines to feed our need here in the state. Because we're really short of gas because so much gas is shut in from the producers, especially out in West Texas. From a financial standpoint, we're doing pretty well, because of the nature of our assets, where they sit and how we're able to perform in this type of situation.

Got it. You mentioned the release last week regarding the increased focus on alternative and renewable energy. I’d like to understand your competitive advantage in utilizing existing assets for renewable diesel or renewable natural gas. What distinguishes your approach to more traditional renewables like wind or solar? What unique offerings do you have that other potential developers might not?

Yes. So on the first part of your question, I guess the point you're making is with our inter and interstate systems, we are able to move around renewables because yes, okay, we have LDCs that are asking for today on interstates, but not a lot. I mean, wind, we're struggling with wind quite honestly, it's hard for us to figure out how to make that work. And we're not going to do anything that doesn't make good economic sense for unitholders. Solar is different if we can go out and acquire solar in areas where there's a lot of sunshine, like out in West Texas and also in other parts of Texas, we'll certainly do that. Because when we're doing it, we're a large consumer of electricity throughout the country, but especially in Texas, and when you can build in a solar priced, very inexpensive supply of electricity. It just makes sense. So that's really our fit. I don't know if we'll ever get involved as far as investing in a solar project because the returns are so much, there's so much less than what we can achieve with other opportunities we have. But we certainly will support solar projects that will provide us with 10, 15 years of what we believe to be very inexpensive power.

Got it. Thank you guys. Much appreciated.

Our next question is from Keith Stanley with Wolfe Research. Please proceed with your question.

Hi, thanks. First, just wanted to confirm there's no lockup period or anything on the unit CenterPoint and OGE will receive in the transaction.

That is correct, Keith.

Okay, great. And the 2021 guidance so you referenced the lower crude spreads and contract expirations as a driver for the year. Do you expect that to continue to be a driver in 2022 and beyond or are we most of the way there now on Permian crude margins kind of resetting to market conditions?

Yes, I think where the spreads have kind of fallen to now, it's about as low as they can go. As we've mentioned on prior calls and conversations, we're doing a lot to figure out a way to make as much of the value stream as we can all the way from the wellheads out in New Mexico and West Texas, all the way to the refineries up in the main continent by utilizing our permit express assets and our Mid Valley assets. So, we believe that we're kind of at the bottom as far as the spreads go, but we also are continuing to work with others to evaluate things that we could possibly do together. And we're looking at converting some of our assets, our crude assets to other uses, that would be more profitable and more efficient for our company. But yes, we've kind of seen it, get about as bad as they can get, and you're down to not much spread across the state, but we're doing everything we can to take advantage of that. In fact, we've kind of got a new team, that's heading that up. It's running our crude group and very pleased with just the early results from this year, where we've increased our cross-haul fairly significantly from where we kind of ended up in the fourth quarter of last year. There's a lot of crude companies out there battling for the crude that is available out in the Permian Basin, we're probably 1 million, 1.5 million barrels less out there than where we thought we'd be a year and a half ago. And there's more capacity built, of course, significantly more than it was a year and a half ago. So we're all scrambling for less barrels, but there's no company that can take the barrel so many different places like we can. So we feel like we've got a good advantage and we're going to take advantage of that.

Thanks for that color. If I could sneak in one other quick one and appreciate the commentary on the company doing pretty well through this unfortunate event in Texas. On the electricity side, just a curious question, do you typically buy power in Texas at spot market rates or are you more on fixed rate type contracts for your electricity needs?

With a variety; in fact, fortunately, we have quite a bit of our megawatts hedged, which has been extremely fortunate today, during the last four or five days, and then we have a variety of different ways we do buy a lot on a day-to-day basis. And we do have some packages bought for different terms. So it's kind of a myriad of different ways we buy it.

Thank you.

And our next question is from Pearce Hammond with Simmons Energy. Please proceed with your question.

Yes, good afternoon, and thanks for taking my question. Investor sentiment, specifically EMT investors, has kind of moved away from the scoop stack play in Oklahoma and toward the Permian over the past few years. So as it pertains to the Enable acquisition, what gets you comfortable with the scoop stack assets and continued producer activity on those assets over the longer term or essentially, what do you think investors do not fully understand or appreciate about the Enable assets? Thank you.

Tom, do you want to take that?

Yes. Mackie, I think the bottom line, the way we look at it is the reserves are there. So if we see something like what happened during the pandemic in the whole country is hit, certainly that will flow down a lot quicker than, say the Permian Basin. But as we see commodity prices recover, and especially the levels that we have now, where we see natural gas prices, not going just higher the rest of this year because of what's happened in the calendar reality of the demand for natural gas, but there's going to be growing demand for natural gas around the world. I mean, it's the cleanest, best way to fuel enormous amounts of electricity. And it's just going to be something that we are very optimistic, and our big believers it's going to be a big growth area for the world, including the U.S., of course, and the reserves are there. I mean, the reserves are in this scoop and in the stack, they're in Oklahoma base and they're over by the Panhandle. As long as commodity prices stay up and at reasonable levels, we think that's an area where rigs will move backhanding and grow production for many years to come. It doesn't take a lot of rigs; I'm sure Enable has said this and we'll say that it doesn't take a lot of rigs on their system to provide volume growth for their system. So if we get back any kind of type of normality of where we were a year and a half ago, we're going to see tremendous growth through those assets. So we're very excited about owning these in the future because of the need for natural gas and oil, in our opinion for many years to come.

Well, thank you Mackie. Appreciate it.

You bet.

Operator, the last of our questions. Well, it looks like maybe we lost the operator. I'll go ahead for those that are still on and we're still connected. Thank all of you for your support. We thank you for joining us today. And we clearly look forward to talking to you about a lot of the exciting stuff that we have happening and of course that will continue to file our S4 just as soon as possible, and have more information to be able to share with you. Thanks, everyone. Stay safe, stay warm.