Q3 2021 Energy Transfer LP Earnings Call

November 3, 2021

Good afternoon, ladies and gentlemen, and thank you for standing by and welcome to the energy transfer third quarter earnings call. At this time all participants are in a listen only mode. A question and answer session will follow the formal presentation should you require operator.

Assistance during the conference. Please press star zero to sing on operator. Please note. This conference is being recorded.

I'll now turn the conference over to your host Tom Long co Chief Executive Officer for Energy transfer. Thank you you may begin. Thank you operator, good afternoon, everyone and welcome to the energy transfer third quarter 2021 earnings call and thank you for joining us today I'm.

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 the press release, we issued earlier this afternoon as well as the slides posted to our website. As a reminder, we will be making forward looking statements within the meaning of section 21 E.

Securities Exchange Act of $19 34.

These statements are based on our current beliefs as well as certain assumptions and information currently available to US and are discussed in more detail on our quarterly report on Form 10-Q for the quarter ended September 32021, which we expect to be filed Tomorrow November the board.

I'll also refer to adjusted EBITDA, and distributable cash flow or DCF, all of which are non-GAAP financial measures you will find a reconciliation of our non-GAAP measures on our website.

I'd like to start today by looking at some of our third quarter highlights.

We generated adjusted EBITDA of $2 6 billion and DCF attributable to the partners of energy transfer as adjusted of $1 $3 billion, our excess cash flow after distributions was approximately $900 million on an.

An incurred basis, we had excess DCF of approximately $540 million after distributions of $414 million and growth capital of approximately $360 million.

Operationally, our NGL transportation, and fractionation and NGL and refined products terminal volumes reached new records during the quarter largely driven by growth in volumes, beating our Mont Belvieu fractionator and legal and terminal as.

As the market continues to recover we are well positioned to benefit from increasing demand and higher margins switching gears to an update on the acquisition of enable midstream partners, which will provide increased scale and the mid continent, and Ark, la Tex regions and improve connectivity for our natural gas and <unk>.

Rail transportation customers, we expect the combination of energy transfers and enables complementary assets to allow us to provide flexible and competitive service to our customers as we pursue additional commercial opportunities utilizing our improved connectivity and increased footprint.

As a reminder, we expect the combined company to generate more than $100 million of annual run rate cost synergies.

And this is before potential commercial synergies.

We continue to believe that the transaction will close before the end of the year.

I'll now walk you through recent developments on our growth projects, starting with our Cushing South pipeline.

In early June we commenced service to provide transportation for approximately 65000 barrels per day of crude oil from our Cushing terminal to our Nederland terminal, providing access for powder River and DJ basin barrels to our Nederland terminal being an upstream connection with our white cliffs pipeline.

This pipe is already being fully utilized and.

And as we mentioned on our last call. We are moving forward with phase two which will increase the capacity to 120000 barrels per day.

Phase two is expected to be in service early in the second quarter of 2022 and is underpinned by third party commitments as a reminder, minimal capital spend is required for this phase.

Next construction on the Ted Collins link is progressing and is now expected to be in service late in the first quarter of 2022.

Ted Collins link will give us the ability to fully load and export unblinded low gravity, Bakken and WCS barrels out of the Houston market.

Showcasing energy Transfer's unique ability to provide a neat bakken barrel to markets along the Gulf coast.

Now turning to our Mariner East system, we have commissioned the next significant pays of the Mariner East project, which brings our current capacity on the Mariner East pipeline system to approximately 260000 barrels per day.

Year to date NGL volumes through the Mariner East pipeline system, and Marcus Hook terminal are up 12% over the same period in 2020.

We are awaiting the issuance of a permit modification for the conversion of the final directional drill two an open cut which will allow us to place. The final segment of Mariner East into service in the first quarter of 2022.

Our Pennsylvania access project, which will allow refined products to flow from the Midwest supply regions.

Into Pennsylvania, New York and other markets in the northeast will began moving refined products. This winter.

Now for a brief update on our Nederland terminal as a reminder, with the completion of the remaining expansion of our LPG facilities that needle in earlier. This year. We're now capable of exporting more than 700000 barrels per day of Ngls from our Nederland terminal.

And when combined with our export capabilities from our Marcus Hook terminal as well as our Mariner west pipeline, which exports of ethane to Canada. Our total NGL export capacity is over $1 1 million barrels per day, which is among the largest in the world.

At our expanded Nederland terminal NGL volumes continued to increase during the third quarter, including export volumes under our orbit ethane export joint venture, which has remained strong year to date through September we have loaded more than 16 million barrels of ethane out of this facility and in total.

Our percentage of worldwide NGL exports has doubled over the last 18 months to nearly 20%, which was more than any other company or country for the third quarter of 2021.

Looking ahead, we expect our total NGL export volumes from Netherlands to continue to increase throughout next year.

In addition demand for supply to refineries remained strong and our crude oil storage at neighborhood is fully contracted.

At Mont Belvieu, we recently brought on a 3 million barrel high rate storage, well, which takes our NGL storage capabilities at Mont Belvieu to 53 million barrels.

And our Permian Bridge project, which connects our gathering and processing assets in the Delaware basin with our G&P assets in the Midland Basin was placed into service in October and is already being significantly utilized.

This project allows us to move approximately 115000 Mcf per day of rich gas out of the Midland basin and to operate existing capacity more efficiently.

While also providing access to additional takeaway options.

In addition, we can easily be expanded to 200000 Mcf per day when needed.

Lastly in July we announced the signing of a memorandum of understanding with the Republic of Panama to study the feasibility of jointly developing a proposed trans Panama Gateway pipeline.

We believe this project would create the most liquid and attractive LPG supply hub in the world and are excited about the opportunity it presents.

Now for an update on.

Our alternative energy activities, where we have continued to make progress on a number of fronts.

In September we entered into a 15 year power purchase agreement with SB energy for 120 megawatts of solar power from its Aiful solar project in northeast, Texas.

This is the second solar project, we are participating in and these agreements provide a good fixed price per megawatt hour.

<unk> generated basis.

So we only pay per power actually generated and deliver it to us.

We're also continuing to explore several opportunities for solar wind and forestry carbon credit projects on our existing acreage in the Appalachian region in.

In particular, we're continuing to jointly pursue solar and wind development on an energy transfer attracting Kentucky with a large utility company and we are in discussions with other large renewable energy developers.

On the carbon capture front, our Marcus Hook project looks financially attractive based upon preliminary cost estimates and design feasibility studies.

This project would involve capturing C O two from the flue gas and delivering it to customers for industrial applications and is used in food and beverage industries.

We're also pursuing several carbon projects related to our assets, including projects involving the capture of C. O two from processing plants for use in enhanced oil recovery or <unk>.

The question <unk>.

We continue to believe that our franchise will allow us to participate in a variety of projects and Bobby carbon capture or other innovative uses as we continue to reduce our carbon footprint.

Lastly, we expect to publish our annual corporate responsibility report to our website shortly.

Now, let's take a closer look at our third quarter results consolidated adjusted EBITDA was $2 6 billion.

Compared to $2 $9 billion for the third quarter of 2020.

DCF attributable to the partners as adjusted was $1 three $1 billion for the third quarter compared to $1 $69 billion for the third quarter of 2020.

While we saw higher volumes across the majority of our segments, including record volumes in the NGL and refined product segment. These benefits did not offset the significant optimization gains in the third quarter of 2020 related to our various optimization groups as well as the one time $103 million.

Gain in our midstream segment.

In addition, the third quarter of 2021 included higher utilities and other winter storm Yuri related expenses.

On October 26th we announced a quarterly cash distributions at 15, and a quarter cents per common unit or <unk> 61 on an annualized basis.

This distribution will be paid on November 19th to unitholders of record as of the close of business on November the pit.

Turning to our results by segment.

And we will start with the NGL and refined products.

Adjusted EBITDA was $706 million compared to $762 million for the same period last year higher terminal services and transportation margins related to the increased throughput on our Nederland and Mariner east pipelines in the third quarter of 2021 were offset by a $55 million decrease.

And our optimization businesses at Mont Belvieu and in the northeast as well as increased Opex and G&A.

<unk> transportation volumes on our wholly owned and joint venture pipelines increased to a record one 8 million barrels per day compared to $1 5 million barrels per day for the same period last year.

This increase was primarily due to increased export volumes eating into our Nederland terminal from the initiation of service on our propane and ethane export projects higher volumes from the Eagle Ford region.

As well as increased volumes on our Mariner East and Mariner West pipeline systems.

And our fractionator has also reached a new record for the quarter with an average fractionated volumes of 884000 barrels per day compared to 877000 barrels per day for the third quarter 2023.

Throughout 2021, we have continued to add volumes to our system and are well positioned to capture additional volumes and capitalized on new opportunities as demand improves.

For our crude oil segment, adjusted EBITDA was $496 million compared to $631 million for the same period last year.

The improved performance on our Bakken and Bayou Bridge pipelines as a result of recovering volumes in the third quarter of 2021 did not offset approximately $100 million.

Of one time items in the third quarter of 2020.

In addition, we had approximately $20 million and other optimization reductions as well as increased opex and G&A expense year over year.

For midstream adjusted EBITDA was $556 million compared to $530 million for the <unk>.

Third quarter of 2020.

This was largely the result of a $156 million increase related to favorable NGL and natural gas prices as well as volume growth in the Permian and the ramp up of recently completed assets in the northeast, which were partially offset by a decrease of $103 million due to the <unk>.

Restructuring and assignment of certain contracts in the Ark La Tex region in the third quarter of 2020.

Gathered gas volumes were 13 million M. N V to use per day compared to $12 9 million and maybe to use per day for the same period last year due to higher volumes in the Permian Ark, La Tex and South Texas regions.

Permian Basin volumes continue to be strong and Midland inlet volumes remain at or near record highs as a result, we're already utilizing our Permian bridge project to enhance the efficiency of our processing in the area by moving some volumes over to our Delaware basin processing plants.

In our Interstate segment, adjusted EBITDA was $334 million compared to $425 million for the third quarter of 2020, primarily due to contract explorations at the end of 2020 on Tiger and FEP as well as a shipper bankruptcy on Tiger and lower demand on Panhandle and trunkline.

Partially offset by an increase in transported volumes on Rover due to more favorable market conditions.

And for our intrastate segment, adjusted EBITDA was $172 million compared to $203 million in the third quarter of last year.

This was primarily due to lower optimization volumes as a result of third party customers shifting to long term contracts from the Permian to the Gulf coast and lower spreads as well as an increase in operating expenses, which were largely offset by increased transportation volumes out of the Permian and an.

And retained fuel revenues and storage margin.

While it impacted us over the comparison periods. The additional long term contracting of third party customers from the Permian to the Gulf Coast is expected to benefit us going forward as the wall hard to Katy basis differential has tightened significantly.

To reduce volatility within our earnings and protect us from falling basis differentials like we saw from the third quarter of 2020 to the third quarter of 2021, we have strategically taken steps to lock in additional volumes under fee based long term contracts, which are exceeding current differentials.

Now turning to our 2021 adjusted EBITDA guidance, our full year 2021, adjusted EBITDA remains $12 9 billion to $13 $3 billion. As a reminder, this range excludes any contributions from the announced enable acquisition.

And moving to a growth capital update for.

The nine months ended September 32021 energy transfer spent $1.08 billion organic growth projects, primarily in the NGL and refined product segment, excluding sun and USA compression capex.

For full year 2021.

We continue to expect growth capital expenditures to be approximately $1 6 billion, primarily in the NGL and refined products midstream and crude oil segments.

And for 2022 and 2023, we continue to expect to spend approximately $500 million to $700 million per year.

Now looking briefly at our liquidity position.

The September 32021, total available liquidity under our revolving credit facilities.

It was approximately $5 4 billion.

And our leverage ratio was three five times per the credit facility.

During the third quarter, we utilized cash from operations to reduce our outstanding debt by approximately $800 million and year to date, we have reduced our long term debt by approximately $6 billion.

We have done a lot of heavy lifting over the last few years as we work to accelerate our debt reduction improve our leverage and best position ourselves to return value to our unit holders.

We expect to generate a significant amount of cash flow in 2022.

Hanging down debt continues to be our top priority. Additionally, our strong performance in 2021 opens the door for the potential that began returning value to our unit holders in the form of distribution increases and or buybacks beginning next year.

During the third quarter, we continue to see volumes recover across several of our systems as well as improved fundamentals. In addition, our nederland and Mariner east expansion projects drove record volumes in our NGL and refined product segment, and we expect total NGL exports.

Growth throughout 2022.

Overall, our assets continued to generate strong cash flow, which allowed us to internally fund our growth projects and further reduce debt in the third quarter, we remain committed to maintaining and improving our investment grade rating and continue to place a significant amount of emphasis on capital discipline.

Deleveraging and maintaining financial flexibility.

We continue to be excited about the acquisition of enable and we believe we will be able to use our enhanced footprint to improve efficiencies and pursue new commercial opportunities.

How do we participate in the evolving energy World is a key focus and we continue to make progress on a number of our alternative energy projects, which we can enhance and effectively grow our energy franchise with preliminary cost estimates looking favorable.

Operator, please open the lineup for our first question.

Thank you at this time, we will be conducting a question and answer session.

To ask a question. Please press star one on your telephone keypad confirmation tone will indicate your line is in the question queue. If at any time you wish to remove your question from the queue. Please press star two for participants using speaker equipment, maybe ask Sharon to pick up your handset before pressing the star keys.

Our first question is from Shneur <unk> with UBS.

Hi, good afternoon, everyone.

Tom maybe we can start off with the quarterly results and how we should think about them with respect to the unchanged guidance.

We saw some higher volumes, but we also saw some lower margins for example in the in the NGL transportation segment costs are up but you would sort of intimated that costs were going to be up earlier this year.

Just wondering if this quarters results was kind of how you've thought it was going to play out as guidance was originally constructed.

Whether we should be thinking that towards the midpoint or towards the lower end.

Is there some seasonality that we should be thinking about with all the contract restructuring bunch of crude I'm. Just wondering if you can sort of give us some color about the shape and how we should be thinking about this specific quarter just given.

Some of the margin compression that we've seen.

Yes, good afternoon.

Sure.

Yeah.

Obviously started the year.

We had that we had the initial guidance. We gave and then we had obviously a very very strong first quarter. So as we look out over the year.

First part of your question there about what we were expecting.

This is this is pretty much in line I will say that there was probably a little bit higher optimization activities that were anticipating.

And some of the segments NGL and refined products crude oil would probably be another one. So this is really playing out maybe.

Maybe a little bit a little bit softer than what we were anticipating but we still feel good about the guidance that we provided I think the last part of your question as to where were.

We would anticipate coming in.

I think in fairness, it probably be coming in at the lower end of that range.

But where we see it right now, but once again have a lot of good positive volumes moving through and with the continued.

Optimization opportunities, we do feel very very good about the about the year.

Great I appreciate the color and maybe as a follow up question.

On slide six you.

Maintaining a $5 million to $700 million a year.

In growth capital for both 2022, and 2023 and that seems to be unchanged, you've made progress paying down debt during the quarter and so forth.

You talked about return of capital along the lines of distribution increases buybacks and so forth.

Is there a new leverage target that we need to be thinking about is that still to get below $4. Five before we can see some sort of a pivot.

Just kind of wondering what your latest thoughts are on that side.

We would our target is still that four to four and a half range.

Yeah.

Okay.

Stated in the past, we do always look at look out at the forecast. So when we make these decisions were not just looking at any one specific point in time, we're looking at our projections and where we see the leverage going so its something thats more of a more of an outlook. So theres not a not a bright line.

If you will so that's the reason we felt comfortable saying that we look at returning returning some.

So we're trying to capital to our unit holders to get in the form of distributions or unit buybacks.

Great. Thank you very much guys.

Thank you Sir.

Yes at the beginning next year I want to make sure I had that into the answer.

Great. Thank you very much I'll jump back into the queue.

Alright. Our next question is from Chase Mulvehill with Bank of America.

Hey, good afternoon.

I guess.

First question around kind of the ethane markets.

Typically we've got for.

Ethane demand, we've got about 280000 barrels a day of cracker capacity that set to come online over the next year and a half or so.

So that's gonna be a sizeable pull on ethane volumes here in the U S.

I guess, maybe if you could kind of talk to how you think or kind of where those volumes. Those ethane volumes come from do you think it's kind of more underlying NGL growth or do you think it's more so.

Less ethane rejection or do you think there's any risk that you actually explore less ethane volumes.

As these crackers come online.

Hello, This is mackie.

Yes, I'd tell you what a great question, we love to these types of questions because energy transfer has positioned itself to really be the leader and not only ethane, but all ngls.

You know we were the first export of ethane.

Canada, and then we have grown our export business ethane at Marcus Hook and out of Nederland. We also are unique in that we control the vast majority of the ethane that we receive at the tailgate of our Frac. So unlike some of our peers, we actually controlling enormous amount of ethane that indeed, the world is search.

<unk> four and we have a.

<unk> and his team we have continuous conversation with companies all over the World South America Asia Europe, China.

We expect that business to grow.

As you know we brought on satellite Fisher.

There'll be bringing their second frac on next year, so it'll be ramping those volumes up we already have approval for our 70000 and 140000 barrel a day expansion at Marcus Hook and we're just looking at negotiating with customers to get on those projects.

<unk> and propane has such a bright future and we are.

Very pleased to be situated where we are to participate in the in those markets.

Okay perfect.

Unrelated follow up.

But it kind of have to ask him vitamins kind of build back better plan.

How do you think this is going to influence ETE strategy over the medium to longer term.

Gosh. This is mackie I'll I'll start Tom might want to follow up I don't I don't even know how to answer that we don't really whatever comes out of those plants.

Out of all of that legislation will deal with that.

When that.

It comes out and once get once it gets fuzzier, Don but we're keeping our head down were in the fossil fuel business, we play an integral part in producing transporting.

Fracking in exporting and also sell into the domestic market is enormous amounts of energy that make a living standards as we have them here and around the world and we are.

Are excited about our industry, we see a long future in this industry we see.

Significantly growing demand for natural gas and especially for propane.

In our natural gas assets, we have a tremendous amount of storage. So it does give us the ability to put product.

Into storage and hedge.

Hedge them out say for example, this winter and then if we have any type of winter event or any type of.

Pricing volatility events, we are able to really benefit from Poland, our products at much higher margins than we expected. So it's hard to predict we certainly positioning ourselves to take advantage of any of the volatility in the market like we saw this past February.

But we certainly don't project that into our budget or into our of our.

Our outlook in the coming years.

Okay.

I mean is it fair to say I guess to that end.

<unk> there has been kind of less volatility in the market. Then you had kind of projected at the beginning of there.

Yeah, Yeah, we don't I'm, sorry, I didn't totally follow up question, but we we.

Sure.

Well situated to.

Benefit not only our revenues, but also the customers and the people of Texas and Europe, but.

As I mentioned, we're also set up this year, if theres any types of coke sales.

Significant volatility in pricing.

We're well positioned to be able to provide what will be necessary for customers in this state and throughout the country.

Okay.

And then.

You had mentioned that the next.

You saw about $33 million and some of that is because of the absolute lower inventory balance that we're keeping also versus $67 million in the quarter and the quarter last year, both those being gains, which you can see that's where the that's really kind of where the where the spread is there.

I think as far as the second part of it yes.

The Bakken pipeline was in there.

Okay, great and I might add in there it's still ramping up.

Is that was that your question Keith just to make sure on that when you're talking about the expansion.

Yes, that's right okay. So that's still ramping.

Into Q4 again.

Yes.

I'll give it a little clearer this is mackie.

He brought that on in August and when we brought that project on the optimization increased.

Capacity the demand charges kicked in on that so the volumes will be with the volumes will be in the drilling needs to pick up in the Bakken to really see those volumes grow but the bottom line is we are receiving demand charges for the incremental capacity that we've created.

Or a significant portion of it.

Got it thanks for that.

Right.

Separate question just on capital allocation. So Tom you said debt repayments still a priority for the company I.

I guess, you have about $1 billion plus of maturities coming up in the first quarter.

Should we assume that's kind of consistent with what <unk> been doing in 2021 that you would repay that with your.

Free cash flow as well.

And then on the distribution I'm just curious when you talk about looking at distribution increases next year.

Is it do you view it I mean, you cut the distribution last year to basically put cash to the balance sheet not because you couldnt pay it.

So how would you look at it when you get into next year.

Is the goal to kind of get back to where you where do you factor in where the yield is just trying to get a sense of.

How you would look at the distribution once you're comfortable with where the balance sheet is.

Alright.

Turn off with the first part of your question on the on the debt.

You probably saw.

The $1 $9 billion already.

November 1st.

One day and have that on December 1st will pay off.

$900 million. So we were going to continue as these maturities.

These maturities come forward, we will continue to pay them down.

Yes.

If some opportunity comes along that maybe you want to term terms somehow I'm not going to take that completely off the table, but right. Now we are continuing to pay down these maturities and even even call. Some early.

As they come up.

I think the <unk>.

Second part of your question.

That's those are discussions that we continue to have with the with the board I wouldn't I wouldn't say that there's any more definitive I can tell you at this time.

And then both the buybacks and the distributions are very much.

Right in the center as we look at them and I want to make sure. The first part of your statement that maintaining financial flexibility is is definitely a top priority.

Thank you.

Our next question is from Jeremy Tonet with J P. Morgan.

Hi, good afternoon.

Jonathan.

Thanks, I just wanted to start off I guess at a higher level.

If you could provide any color as far as what youre seeing on producer activity.

Especially as you're heading into 'twenty two year ahead.

We've seen kind of a bifurcation with the privates getting after it in the public seemed more discipline do you expect those trends to continue or do you see any anything changing there and how much does this value across these.

Yeah. Jeremy This is Mackie, you said, it well and Thats kind of what we saw this year is what we are seeing going into next year.

The majors are just much more cautious they are Washington capital much more closer than a lot of the independents.

At least around love our assets, we are seeing more activity and more production coming up with a smaller company with smaller independent however.

Well some of these major is especially out in the Permian basin in the northern Louisiana area and even in the.

In the Marcellus Utica, we're seeing rigs come back in as everybody knows I think rigs.

Louisiana are up about 45% from where they were a year ago, well over a year ago, and we're seeing the similar type growth.

The Permian Theres still a lot of ducks outlet Permian that have not been completed a number of them have been but we are seeing a lot of those now being completed as we go into 2022.

I think we would describe it at least around our system is just consistent growth not just a hard ramp first or second quarter, but just consistent growth throughout the year, both in rigs and in volume growth out in the Permian.

Do expect.

<unk> growth.

More leaner gas in northern Louisiana.

We see kind of similar gradual growth in the Eagle Ford down in South, Texas on our asset down there.

And just wanted to pick up on some of your comments before and certainly hydrocarbons are important to improving the standard of global living here, but looking at slide seven and talk about the alternative energy group here and just wanted to see which specific opportunities are you guys kind of focused on right now do you see opportunities.

Black carbon or using right of ways for electric transmission.

And I know everything coming out of D C as clear as mud, but if we get things like higher 45 cues of renewables and Couldnt qualified income what could this mean for you guys.

Yes, Tom.

Of course are daily following that and we're looking for what comes out of Congress with the 45 to you another tax benefits around the renewables as we've said before our focus is really on the mission is to our assets.

Other words around our <unk>.

Processing plant.

Trading facilities, we're looking to capture carbon so whether we do it partner up with somebody or allow somebody else to capture that.

We are also looking at some.

Catherine from carbon off some of our facilities up in the northeast.

We have our Marcus Hook facility, we're looking to capture some yeah.

We've done some preliminary studies, they actually look very promising at some rates return that makes sense and so we will continue to pursue those.

We're also looking at carbon capture down.

South Texas.

We will either be sequestered or part of an EUR projects. So we are proceeding we're doing that on a daily basis common. His team are looking at deals all across the board, whether it's black carbon or whether it's.

Taking natural gas and converting it to a gasoline or whether it's renewable diesel and transporting that who are a decent pipeline system. We're looking at all of that and we will continue to.

Participating that as we have around the the solar business, where we are not.

Invested in that from a capital perspective, but we're certainly investing in our commitment to purchase what we see is very inexpensive power. So we are supporting nobles in that in that way or that manner, but we will continue to pursue those that makes sense and we do expect to.

Consequently, some of those in the distant future not necessarily tremendous amount of capital, but we do see.

Projects that may involve up to $20 million to $30 million of capital around.

Sequestration.

So that isn't it.

A focus of ours as we go into 'twenty two and beyond.

Got it that was a very helpful answer.

Our next question is from Colton Bean with Tudor Pickering Holt.

Maybe just circling back to the comments on the intrastate segment. It looks like the transportation margin on a per unit basis fell quite a bit relative to the first half of the year. So just wanted to clarify it sounded like that was primarily attributable to shorter term.

I'm sorry.

Yes.

Interstate.

Interestingly, Texas, Texas pipes, Brian.

Brian.

Yes, it looks like the transportation margin on a per unit basis fell a decent bit relative to what we saw in first half and I think Tom you might have spoken to this but just wanted to clarify it sounded like that was primarily attributable to higher rate short term contracts that maybe whistler change that dynamic there just wanted to understand what was what was kind of going on between first half of the year.

In Q3.

You bet. This is mackie again.

Prior to the last 342 inches they've come on in the last couple of years.

That was kind of our bread and butter is moving gas across the state we saw spreads $1 $52 and those of course started to come in.

So we started the strategy a couple of years ago to look to secure longer term commitment at not dollar dollar 50 spread but a good healthy spread and that's what we began doing so when you look at the third quarter of 2020, the spreads were as much as 75 or 80% on average for that quarter, we did secure.

<unk>.

Prior I mean I'm sorry.

Last year that impacted third quarter of this year and lower than that 75, or 80 cents, but much higher than where the spreads are today.

It's a strategy that made sense to us where we could see the spreads coming in at least in the short term. We think this will be short lived in two to three years. We believe the basis will blow back out there will be more need look at the growth in the Permian Basin natural gas is just incredible but in the meantime, we did want to secure some of our capacity at healthy.

Margins for longer term contracts.

Kevin with this.

And then kind of in the last two the Greenfields to your point.

The base run rate look at ahead of just kind of looking at where the basis goes from here.

Yeah I'll answer it like.

We've seen spreads fall to 25, 2025 30 tier as of recent.

We do believe and I believe the industry believes that over the next year and a half two years, but that will start moving back out we may see 75 cents or a dollar we have some of our competitors out there talking about building and maybe another 42 inch what we're trying to tell the marketplace in the producers and shippers before they commit to the project. We will have capacity, we have path to come.

Available in two to three years from now.

And we'd love to lock it in for prices similar to what they would pay on Newbuild on Greenfield projects. So we are very well positioned to kind of weather. The storm here is all the.

42 inches of being completely as the gas begins to grow and fill them up.

Once they all become comfortable we're very well positioned to capture a bigger spread on capacity. It will have on our on our <unk>.

Gas system.

Got it and maybe just a little bit more of a niche topic here.

C P. B R assets, you'll still have any exposure there in terms of.

What we're seeing on price hikes in the coal market right now or Alternatively is this a more attractive seller's market, where you might look to divest some of those legacy assets.

No I wouldn't say that.

But there would be any any opportunity for or a spike there as you know that's a very small very very small piece.

Sits up there, it's a royalty to royalty business. So I wouldn't guide you toward anything there as far as divestiture.

There's no plans no no dialogue going on that front.

Got it thank you.

Our next question is from Michael Blum with Wells Fargo.

Hi, Thanks, good afternoon, everyone.

I wanted to ask about Rover.

You highlighted a $13 million increase in revenue just wanted to hear what the dynamics are on Rover right now how much of that is contracted and I guess given that information is pretty tight on takeaway is there an ability to sign up.

More producers it at higher rates.

Yeah, Hey, Michael this is mackie.

What a great project that hey, that's really turned out well for us.

We saw for example, we saw a hiccup on pet Coke pipeline here a couple of months ago.

All of the value of that pipeline increase even more so with the difficulty that we see in the at least the near term over the next two to 345 years, how difficult it will be to get another interstate pop unapproved out in that area, but we're still well positioned.

We do have.

So I'd, probably approximately over 90% of it under long term contracts.

On a month to month basis, many times, we're selling capacity at tariff rate, depending on the month, depending on whether theyre going to dawn or are going south of <unk>.

It's such a excellently strategically located asset as we see volumes grow out of the Marcellus Utica.

It's kind of unique in the sense. They can move barrels up north into Canada, and as you know it can move barrels all the way down to the Gulf coast to.

<unk> supplies for LNG facilities as well other marks on the Gulf Coast.

We we.

Consistently move about three two to 3.4, we can move as much as three point.

Five five I believe it is.

So we will continue to see that kind of grow both in filling it up to the Max and also.

At Max tariff rate is.

The future as we go into the future.

Got it and then just a quick follow up for me.

So your Capex for 'twenty, two 'twenty three of that $5 million to $700 million per year range.

I'm, assuming that does not.

Does not include any potential spending on these initiatives you have going on in Panama.

The question is if if this mou becomes an RFID project.

Panama, how does that change those numbers.

It would certainly add to those numbers, but getting that project to <unk>. It's down the road, we're probably talking at least 12 months to get net to <unk>.

So we wouldn't see any material spending until probably 'twenty three.

Got it thank you.

Our next question is from Pearce Hammond with Piper Sandler.

Yes, good afternoon, and thanks for taking my question I just had one question today Mackie as you look out over the next few years.

<unk> supply demand when do you see a need for more fractionation capacity at Mont Belvieu.

Well, what a great question and where we are positioned to capitalize on that when we find the answer that question.

We're being very capital disciplined so we have not completed our eighth frac, but we're certainly watching it very closely both for volumes that are committed to our plan.

And also volumes committed to third party plants. So just from a looking.

Looking from a rise in Retrans for US, we don't see the need for one for at least the next.

Six to nine months, but we evaluate on a quarterly basis and we do expect that at some point in 2022, we will have to take a serious look at completing that eight Brad because we do expect the volumes to begin growing.

As long as commodity prices continue to stay where they are now and it sure looks like they will.

Thank you Mackie.

Our next question is from Christine Cho with Barclays.

Hi, everyone. Thanks for squeezing me in.

I just wanted to how should we think about costs going up in 'twenty two.

O&M and G&A side, and then to your inflation trackers.

Have any caps to them and to the extent that it tracks something like a CPI or PPI should we think that should we assume the entire increase will be reflected in rates next year or what competitive pressures limit some of that the increase that you would actually material.

Okay.

I can start on the second half of that maybe most of it.

Yes in most of our contracts certainly in all of our liquid contracts around our transportation and fractionation and around our crude contracts. We have an index. It's typically typically a FERC index, but to give you. An example, I believe the FERC index. This year I believe that starting July It goes July for the next July was negative.

So we actually didn't have.

Any kind of uptick in that.

While we see this inflation however, what that sets up for US next July we expect that to move up significantly we've we've heard as much as five or 6% and we do have those increases in the vast majority of our Arlington contracts as well as in many if not most of our gas contracts.

We do have whether it's the CPI index and a gas contract for the FERC index and our liquid contracts. We do have that in the majority of those who will benefit from.

Or at least not be harmed.

The inflationary growth.

And cutting costs.

And we should.

I expect that you would put the entire increase through competitive pressures wooden wooden.

Precludes you from just doing a part of it.

It may on future contracts, but when I'm, referring to all the existing contracts, we have today to move products through our systems already have that language in it okay. Both in crude.

And then on the NGL segment just curious.

One of your peers had talked about.

Incentive rates in the Permian I'm curious if you guys did the same thing or if the segment was really just all optimization headwinds.

Okay.

Yeah, I'm not sure what an incentive rate is the rate. We will do is the highest rate we can possibly get from our shippers.

From what the market will allow.

Oh well.

Well I guess would you say, they trended lower quarter over quarter.

Oh, I'm, sorry, so you're saying, it's kind of where the market places yes.

Just like crude just like natural gas per liter in a short period of time NGL across all has been overbuilt. Fortunately much of the barrels that are that come to our system and they will come to our system in the future already dedicated but those barrels that are out there at the tailgate of third party third party facilities.

There, we go out and try to get on a monthly basis, it's gotten very competitive.

The TNF prices are significantly lower than where they were years ago.

Got it thank you.

No.

Our next question is from Michael Lapides from Goldman Sachs.

Hey, guys. Thanks for taking my question look we're eight or nine months removed from winter storm. Yuri can you can you give a little insight on what you're seeing in the contracting market for gas storage, especially in Texas, whether you're already entering significant new contracts and kind of taken a little bit of the maybe the margin upside but also.

The margin downside of spreads move around but getting more of a fixed fee payment and just kind of how the market for gas storage overall is moving after that event.

Yeah.

You bet. This is mackie again.

Yes.

A variety we effected a lot more demand or a lot more desperate I'd say demand to come secure storage. We certainly have sold more storage than we did last year at much more favorable rates and also some swing rights to that.

We are still in negotiations with a number of parties and power plant.

We're swinging service service and storage service for this winter, but some of the companies had panicked or havent don't seem as worried.

As we thought they would have to what happened at Uri, but once again, we're well positioned whether or not we've already done as we have some new deals or we're positioned to be able to provide that service as they need it this winter.

Got it. Thank you guys much appreciate it.

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

Thank you all once again for joining us today and for your support and we look forward to talking to you in the near future.

[laughter].

This concludes today's conference energy transfer. Thanks, you for your participation you may disconnect your lines at this time.

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Should you require operator assistance during the conference. Please press star zero to sing on operator please.

Please note. This conference is being recorded I will now turn the conference over to your host Tom Long Co Chief Executive Officer for energy transfer. Thank you you may begin.

Operator, good afternoon, everyone and welcome to the energy transfer third quarter 2021 earnings call and thank you for joining us today.

As a reminder, we will be making forward looking statements within the meaning of section 21 E C.

Securities Exchange Act of $19 34.

I'll also refer to adjusted EBITDA, and distributable cash flow or DCF, all of which are non-GAAP financial measures you will find a reconciliation of our non-GAAP measures on our website.

Like to start today by looking at some of our third quarter highlights.

We incurred basis, we had excess DCF of approximately $540 million after distributions at $414 million and growth capital of approximately $360 million.

<unk> transportation customers, we expect the combination of energy transfers and enables complementary assets to allow us to provide flexible and competitive service to our customers as we pursue additional commercial opportunities utilizing our improved connectivity and increased foot grip.

As a reminder, we expect the combined company to generate more than $100 million of annual run rate cost synergies.

And this is before potential commercial synergies.

We continue to believe that the transaction will close before the end of the year.

I'll now walk you through recent developments on our growth projects, starting with our Cushing South pipeline.

This pipe is already being fully utilized and as we mentioned on our last call. We are moving forward with phase two which will increase the capacity to 120000 barrels per day.

Phase two is expected to be in service early in the second quarter of 2022 and is underpinned by third party commitments as a reminder, minimal capital spend is required for this space.

Next construction on the Ted Collins link is progressing and is now expected to be in service late in the first quarter of 2022.

Ted Collins link will give us the ability to fully load and export unblinded low gravity, Bakken and WCS barrels out of the Houston market.

Showcasing energy transfer has unique ability to provide a neat bakken barrel to markets along the Gulf coast.

Year to date NGL volumes through the Mariner East pipeline system, and Marcus Hook terminal are up 12% over the same period in 2020.

Our Pennsylvania access project, which will allow refined products to flow from the Midwest supply regions.

Pennsylvania, New York and other markets in the northeast will began moving refined products. This winter.

Now for a brief update on our Nederland terminal as a reminder, with the completion of the remaining expansion of our LPG facilities at Nederland earlier. This year. We are now capable of exporting more than 700000 barrels per day of Ngls from our Nederland terminal.

At our expanded Midland terminal NGL volumes continued to increase during the third quarter, including export volumes under our orbit ethane export joint venture, which has remained strong year to date through September we have loaded more than 16 million barrels of ethane out of this facility and in total our.

Our percentage of worldwide NGL exports has doubled over the last 18 months to nearly 20%, which was more than any other company or country for the third quarter of 2021.

Looking ahead, we expect our total NGL export volumes from Netherlands to continue to increase throughout next year.

In addition demand for supply to refineries remained strong and our crude oil storage at Nathan is fully contracted.

At Mont Belvieu, we recently brought on.

A 3 million barrel high rate storage, well, which takes our NGL storage capabilities at Mont Belvieu to 53 million barrels.

This project allows us to move approximately 115000 Mcf per day of rich gas out of the Midland basin and to operate existing capacity more efficiently.

While also providing access to additional takeaway options in.

In addition, we can easily be expanded to 200000 Mcf per day when needed.

Lastly in July we announced the signing of a memorandum of understanding with the Republic of Panama to study the feasibility of jointly developing a proposed trans Panama Gateway pipeline.

We believe this project would create the most liquid and attractive LPG supply hub in the world and are excited about the opportunity it presents.

Now for an update.

On our alternative energy activities, where we have continued to make progress on a number of fronts.

In September we entered into a 15 year power purchase agreement with SB energy for 120 megawatts of solar power from its Aiful solar project in northeast, Texas.

This is the second solar project, we are participating in and these agreements provide a good fixed price per megawatt hour.

They generated basis.

So we only pay for power actually generated and deliver it to us.

We're also continuing to explore several opportunities for solar wind and forestry carbon credit projects on our existing acreage in the Appalachian region input.

In particular, we're continuing to jointly pursue solar and wind development on <unk>.

<unk> transfer attracting Kentucky with a large utility company and we are in discussions with other large renewable energy developers.

On the carbon capture front, our Marcus Hook project looks financially attractive based upon preliminary cost estimates and design feasibility studies. This.

This project would involve capturing cotwo from the flue gas and delivering it to customers for industrial applications and is used in food and beverage industries.

We're also pursuing several carbon projects related to our assets, including projects involving the capture of <unk> from processing plants for use in enhanced oil recovery or <unk>.

<unk>.

We continue to believe that our franchise will allow us to participate in a variety of projects in Barbie carbon capture or other innovative uses as we continued to reduce our carbon footprint.

Lastly, we expect to publish our annual corporate responsibility report to our website shortly.

Now, let's take a closer look at our third quarter results consolidated adjusted EBITDA was $2 6 billion.

Compared to $2 9 billion for the third quarter of 2020.

DCF attributable to the partners as adjusted was $1 three 1 billion for the third quarter compared to $1 $69 billion for the third quarter of 2020.

Gain in our midstream segment.

In addition, the third quarter of 2021 included higher utilities and other winter storm Yuri related expenses.

On October 26th we announced a quarterly cash distributions at 15, and a quarter cents per common unit or <unk> 61 on an annualized basis. This.

This distribution will be paid on November 19th to unitholders of record as of the close of business on November the fifth.

Turning to our results by segment.

We will start with the NGL and refined products adjusted EBITDA was $706 million compared to $762 million for the same period last year higher terminal services and transportation margins related to the increased throughput on our Nederland and Mariner east pipelines in the third quarter of 2021.

Were offset by a $55 million decrease in our optimization businesses at Mont Belvieu and in the northeast as well as increased Opex and G&A.

NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record one 8 million barrels per day compared to $1 5 million barrels per day for the same period last year.

This increase was primarily due to increased export volumes feeding into our Nederland terminal from the initiation of service on our propane and ethane export projects higher volumes from the Eagle Ford region.

As well as increased volumes on our Mariner East and Mariner West pipeline systems.

And our fractionator has also reached a new record for the quarter with an average fractionated volumes of 884000 barrels per day compared to 877000 barrels per day for the third quarter of 2020.

Throughout 2021, we have continued to add volumes to our system and are well positioned to capture additional volumes and capitalized on new opportunities as demand improves.

For our crude oil segment adjusted EBITDA was $496 million.

Compared to $631 million for the same period last year.

The improved performance on our Bakken and Bayou Bridge pipelines as a result of recovering volumes in the third quarter of 2021 did not offset approximately $100 million of one time items in the third quarter of 2020.

Addition, we had approximately $20 million and other optimization reductions as well as increased opex and G&A expense year over year.

For midstream adjusted EBITDA was $556 million compared to $530 million for the third quarter of 2020.

The restructuring and assignment of certain contracts in the Ark La Tex region in the third quarter of 2020.

Gathered gas volumes were 13 million <unk> per day compared to $12 9 million <unk> per day for the same period last year due to higher volumes in the Permian architects and South Texas regions.

Partially offset by an increase in transported volumes on Rover due to more favorable market conditions.

And for our intrastate segment, adjusted EBITDA was $172 million compared to $203 million in the third quarter of last year.

And retained fuel revenues and storage margin.

While it impacted us over the comparison periods. The additional long term contracting of third party customers when the Permian to the Gulf Coast is expected to benefit us going forward as the wall hard to Katy basis differential has tightened significantly.

Now turning to our 2021 adjusted EBITDA guidance, our full year 2021, adjusted EBITDA remains $12 9 billion to $13 3 billion. As a reminder, this range excludes any contributions from the announced enable acquisition.

And moving to a growth capital update for the.

The nine months ended September 32021 energy transfer spent $1.08 billion organic growth projects, primarily in the NGL and refined product segment, excluding sun and USA compression capex.

For full year 2021.

We continue to expect growth capital expenditures to be approximately $1 6 billion, primarily in the NGL and refined product midstream and crude oil segment.

And for 2022 and 2023, we continue to expect to spend approximately $500 million to $700 million per year.

Now looking briefly at our liquidity position.

The September 32021, total available liquidity under our revolving credit facilities.

Was approximately $5 4 billion.

And our leverage ratio was three five times per the credit facility.

During the third quarter, we utilized cash from operations to reduce our outstanding debt by approximately $800 million.

And year to date, we have reduced our long term debt by approximately $6 billion.

We have done a lot of heavy lifting over the last few years as we work to accelerate our debt reduction improve our leverage and best position ourselves to return value to our unit holders.

We expect to generate a significant amount of cash flow in 2022, and paying down debt continues to be our top priority.

Additionally, our strong performance in 2021 opens the door for the potential began returning value to our unit holders in the form of distribution increases and or buybacks beginning next year.

Growth throughout 2022.

Deleveraging and maintaining financial flexibility.

We continue to be excited about the acquisition of enable and we believe we will be able to use our enhanced footprint to improve efficiencies and pursue new commercial opportunities.

We participate in the evolving energy World is a key focus and we continue to make progress on a number of our alternative energy projects, which we can enhance and effectively grow our energy franchise with preliminary cost estimates looking favorable.

Operator, please open the lineup for our first question.

Thank you at this time, we will be conducting a question and answer session.

To ask a question. Please press star one on your telephone keypad confirmation tone will indicate your line is in the question queue. If at any time you wish to remove your question from the queue. Please press star two for participants using speaker equipment to maybe ask Sharon to pick up your handset before pressing the star keys.

Our first question is from Shneur <unk> with UBS.

Hi, good afternoon, everyone.

Tom maybe we can start off with the quarterly results and how we should think about them with respect to the unchanged guidance.

Just wondering if this quarters results was kind of how you've thought it was going to play out is as guidance was originally constructed.

Whether we should be thinking that towards the midpoint or towards the lower end.

Is there some seasonality that we should be thinking about with all the contract restructuring such a crude I'm. Just just wondering if you can sort of give us some color about the shape and how we should be thinking about this specific quarter just given.

Some of the margin compression that we've seen.

Yeah Yeah.

There.

We.

Obviously started the year.

We had that we had the initial guidance. We gave and then we had obviously a very very strong first quarter. So as we look out over the year.

The first part of your question there about what we were expecting.

This is this is pretty much in line I will say that it was probably a little bit higher optimization activities that were anticipating.

And some of the segments NGL and refined products crude oil would probably be another one. So this is really playing out maybe.

Maybe a little bit a little bit softer than what we were anticipating but we still feel good about the guidance that we provided I think the last part of your question as to where were.

We would anticipate coming in.

I think in fairness, it probably be coming in at the lower end of that range is probably where we see it right now.

Once again have a lot of good positive volumes moving through and with the continued.

Optimization opportunities, we do feel very very good about the about the year.

Great I appreciate the color and maybe as a follow up question.

On slide six you you maintained a $5 million to $700 million a year.

In growth capital for both 2022, and 2023 and that's that seems to be unchanged, you've made progress paying down debt during the quarter and so forth.

You talked about return of capital along the lines of distribution increases buybacks and so forth.

Is there a new leverage target that we need to be thinking about is that still to get below four and a half before we can see some sort of a pivot.

Just kind of wondering what your latest thoughts are on that side.

We would our target is still that four to four and a half range.

<unk>.

Okay.

Stated in the past, we do always look at look at it the forecast. So when we make these decisions were not just looking at any one specific point in time, we're looking at our projections and where we see the leverage going so its something thats more of a more of an outlook. So theres not a not a bright line.

If you will and so that's the reason we felt comfortable saying that we look at returning returning some.

Sorry, returning capital to our unit holders in the form of distributions or unit buybacks.

Great. Thank you very much guys.

Thank you Sir.

Yes at the beginning next year I want to make sure I had that into the answer.

Great. Thank you very much I'll jump back into the queue.

Alright. Our next question is from Chase Mulvehill with Bank of America.

Hey, good afternoon.

I guess.

First question around kind of the ethane market.

Typically we've got for.

Ethane demand, we've got about 280000 barrels a day of cracker capacity that set to come online over the next year and a half or so.

So that's going to be a sizable pool ethane volumes here in the U S.

So I guess, maybe if you could kind of talk to how you see kind of where those volumes those ethane volumes come from do you think it's kind of more underlying NGL growth.

Or do you think it's more so.

Less ethane rejection or do you think there's any risk that you actually explore less ethane volumes.

As these crackers come online.

Hello, This is mackie.

I tell you what a great question, we love to these types of questions because energy transfer has positioned itself to really be the leader and not only ethane, but all ngls.

As you know we were the first export of ethane.

Into Canada, and then we've grown our export business ethane at Marcus Hook and out of Nederland.

We also are unique in that we control the vast majority of the ethane that we receive at the tailgate of our Fracs. So unlike some of our peers, we actually controlling enormous amount of ethane that indeed, the world is searching for and we have with RV and his team we have continuous conversation with companies all.

Over the World South America Asia, Europe, China, we expect that business to grow.

You know we brought on satellite issue here and.

There'll be bringing their second frac on next year. So it will be ramping those volumes up we already have approval for our 70000 and 140000 barrel a day expansion at Marcus Hook and we're just looking at negotiating with customers to get the <unk> on those projects, so ethane and propane has such a bright future and we are.

Very pleased to be situated where we are to participate in.

In those markets.

Okay perfect.

Unrelated follow up.

But it kind of have to ask him vitamins kind of build back better plan.

How do you think this is going to influence strategy over the medium to longer term.

Gosh. This is mackie I'll start Tom might want to follow up I don't I don't even know how to answer that we don't really whatever comes out of those plants.

And out of all that legislation will deal with that.

That.

It comes out and once get once it gets buzzard, Don but we're keeping our head down were in the fossil fuel business, we play an integral part in.

Producing transporting.

<unk> and exporting and also sell into the domestic market is enormous amounts of energy that make the living standards as we have them here and around the world.

Are excited about our industry, we see a long future in this <unk>.

Industry, we see a significantly growing demand for natural gas and especially for propane.

In ethane or ethylene and propylene and other very critical.

Products that are such a big role in everyday life. So we don't really we try of course, we pay attention to politics of course, we pay attention to any tax impacts. It may have on our on our partnership but we don't really get all worrying caught up and that we will deal with it when it comes out but in the meantime, we're just trying to generate revenues for you.

No holders.

Okay, perfect I'll turn it back over.

Our next question is from Jean Ann Salisbury with Bernstein.

Hi could you kind of talk about why mainly optimization has lagged your estimate and is there a minimum that optimization could be and army near that here.

This is Mackie again, yes, Tom was referring to.

Optimization opportunities, especially material ones like we saw in 2020.

You can't predict them you can't predict a pandemic you can't predict oil go into negative zero and you can't predict it bounce back up in a relatively small period of time.

<unk> or $50 a barrel so.

The fortunate thing about our assets, both our crude assets, our Ngls and.

In our natural gas asset is we have a tremendous amount of storage. So it does give us the ability to put product in.

Storage and and hedge them out say for example, this winter and then if we have any type of winter event or any type of.

Pricing volatility event, we are able to really benefit from Poland, our products at much higher margins than we expected. So it is hard to predict we certainly positioning ourselves to take advantage of any of the volatility in the market like we saw this past February.

But we certainly don't project that into our budget or into <unk>.

Our outlook in the coming year.

Okay.

I mean is it fair to say I guess that <unk>.

Sorry, there has been kind of less volatility in the market. Then you had kind of projected at the beginning of their.

Okay.

Yeah, Yeah, we don't I'm, sorry, I didn't totally followup question, but we.

We were.

Well situated to.

Benefit not only our revenues, but also the customers and the people of Texas in Europe, but.

As I mentioned, we're also set up this year, if theres any types of coke sales or any type of significant volatility in pricing.

We're well positioned to be able to provide what will be necessary for customers in this state and throughout the country.

Okay that makes sense.

And then.

And you'd mentioned that the next the next satellite <unk> kind of go neck sometime next year do you have a sense of when in the year that will start when do you get do you start getting paid basically window shipments.

Yes. The second question I believe the latest we heard was the third quarter of next year I can't say that with absolute certainty, but that's the last thing we heard I admit to check on that before this call I have not heard an update I believe thats accurate.

Thanks, a lot that's all for me.

Our next question is from Keith Stanley with Wolfe Research.

Hi.

Good afternoon, one one small one just to follow up on the quarter.

So you've talked to the I guess the optimization headwinds. There is also a driver cited of unfavorable crude inventory valuation adjustments was that a big driver for the crude segment.

And I guess also with the Bakken pipeline expansion fully in the crude segment results for Q3.

Let's start with the inventory gains.

This quarter.

You saw about $33 million and some of that is because of the absolute lower inventory balance that we're keeping also versus $67 million in the quarter and the quarter last year, both those being gains, but you can see that's where the that's really kind of where the where the spread is there.

I think as far as the second part of it yes.

The Bakken pipeline wasn't there.

Okay, great and I might add and they are still ramping up.

Okay is that was that your question Keith just to make sure on that when you're talking about the expansion.

Yes, that's right okay. So that's still ramping.

Into Q4 again.

Yes.

I'll give a little clearer this is mackie.

Brought that on in August and when we brought that project on the optimization increase.

Capacity the demand charges kick in on that so the volumes will be what the volumes will be in the drilling needs to pick up in.

In the Bakken to really see those volumes grow but the bottom line is we are receiving demand charges for the incremental capacity that we've created.

Or a significant portion of it.

Got it thanks for that.

Got it.

Separate question just on capital allocation. So Tom you said debt repayments still a priority for the company.

I guess, you have about $1 billion plus of maturities coming up in the first quarter.

Should we assume that.

It kind of consistent with what <unk> been doing in 2021 that you would repay that with your.

Free cash flow as well.

And then on.

On the distribution I'm just curious.

When you talk about looking at distribution increases next year.

Is it do you view it I mean, you cut the distribution last year to basically put cash to the balance sheet not because you couldnt pay it.

So how would you look at it when you get into next year.

Is the goal to kind of get back to where you where do you factor in where the yield is just trying to get a sense of.

How you would look at the distribution once you're comfortable with where the balance sheet is.

Alright can you tell us.

Start off with the first part of your question on the on the debt.

These problems.

The $1 $9 billion already and.

November one 1 billion of that and on December 1st we will pay off pay off another $900 million. So we were going to continue as these maturities.

These maturities come forward, we will continue to to pay them down.

If if some opportunity that comes along that makes you want to term terms somehow I'm not going to take that completely off the table, but right. Now we are continuing to pay down these maturities and even even could call. Some early.

As they come up.

I think the second part of your question.

Those are discussions that we continue to have with the with the board I wouldn't I wouldn't say that there's any more definitive I can tell you at this time.

Then both the buybacks and the distributions are very much front.

Front and center as we look at them, but I want to make sure. The first part of your statement that maintaining financial flexibility is is definitely a top priority.

Thank you.

Our next question is from Jeremy Tonet with J P. Morgan.

Hi, good afternoon.

Jonathan.

Thanks, I just wanted to start off I guess.

At a high level, if you could provide any color as far as what youre seeing on producer activity.

Especially as you're heading into 'twenty two year ahead.

We've seen kind of a bifurcation with the privates getting after it in the public seeing more discipline do you expect those trends to continue or do you see any anything changing there and how much does this value across the nation.

Yes, Jeremy this is Mackie, you said, it well and that's kind of what we saw this year is what we are seeing going into next year the.

The majors are just much more cautious they are Washington capital much more closer than a lot of the independents.

At least around a lot of our assets, we are seeing more activity and more production coming out with a smaller company with smaller independent however.

Well some of these majors, especially out in the Permian basin.

In the northern Louisiana area and even in the.

In the Marcellus Utica, we're seeing rigs come back in as everybody knows I think rigs.

The Ana are up about 45% from where they were a year ago, well over a year ago and we're seeing the similar type growth out in the Permian, There's still a lot of ducks Alpha Permian that have not been completed a number of them have been but we are seeing a lot of those now being completed as we go into 2022.

We would describe it at least around our system is just consistent growth not just a hard ramp first or second quarter, but just consistent growth throughout the year, both in rigs and in volume growth out in the Permian we.

We do expect faster growth on the more leaner gas in northern Louisiana.

And we see kind of similar.

Gradual growth in the Eagle Ford down in South, Texas on our asset down there.

And just wanted to pick up on some of your comments before and certainly.

Hydrocarbons are important to improving the standard of global living here, but looking at slide seven and talk about the alternative energy group here.

And just wanted to see which specific opportunities are you guys kind of focused on right now do you see opportunities.

Black carbon or using right of ways for electric transmission.

And I know everything coming out of D C as clear as mud, but if we get things like higher 45, Qs of renewables and Couldnt qualified income what could this mean for you guys.

Yes, Tom and his group of course are daily following that and Theyre looking for what comes out of Congress with the 45 to you another tax.

Benefits around the renewables as we've said before our focus is really on the mission to our assets.

Other words around our <unk>.

Processing plant.

Trading facilities, we're looking to capture carbon suppose whether we do it partner up with somebody or allow somebody else to capture that.

We are also looking at some.

Catch them some carbon off some of our facilities up in the northeast.

We have our Marcus Hook facility, we're looking to capture some yes, we've done some preliminary studies they actually look very promising at rates of return that makes sense and so we will continue to pursue those.

We're also looking at some carbon capture down.

South Texas.

We will either be sequestered or part of an EUR projects. So we are proceeding we're doing that on a daily basis, Tom and his team are looking at deals all across the board, whether it's black carbon or whether it's.

Taking natural gas and converting it to a gasoline or whether it's renewable diesel and transporting that two are a decent pipeline system. We're looking at all of that and we will continue to.

Anticipating that as we have around the the solar business, where we are not.

Invested in that from a capital perspective, but we're certainly investing in our commitment to purchase what we see is very inexpensive power. So we are supporting with nobles in that in that way or that matter, but we will continue to pursue those that makes sense and we do expect to.

Consequently, some of those are the distant future not necessarily tremendous amount of capital, but we do see.

Other projects that may involve up to $20 million to $30 million of capital around Cotwo sequestration.

Is it going to remain a focus of ours as we go into 'twenty two and beyond.

Got it that was a very helpful answer.

Our next question is from Colton Bean with Tudor Pickering Holt.

Like that was primarily attributable to shorter term.

I'm sorry.

Yeah.

Interstate.

Interestingly, Texas, Texas pipes.

Brian.

In Q3.

You bet. This is mackie again.

So prior to the last 342 inches that have come on in the last couple of years.

That was kind of our bread and butter is moving gas across the state we saw spreads of $1 $52 and those of course started to come in so we started the strategy a couple of years ago to look to secure longer term commitment at not dollar dollar 50 spread but a good healthy spreads and thats, what we began doing so.

When you look at the third quarter of 2020, the spreads were as much as 75 or 80% on average for that quarter, we did secure Germany.

Prior I mean I'm sorry.

Last year that impacted third quarter of this year at lower than that 75% <unk>, but much higher than where the spreads are today.

It's a strategy that made sense for us where we could see the spreads coming in at least in the short term. We think this will be short lived in two to three years. We believe the basis will blow back out there will be more need to look at the growth in the Permian basin natural gas, it's just incredible but in the meantime, we did want to secure some of our capacity at healthy.

Margins for longer term contracts.

Kevin with this.

And then it kind of even the last of the Greenfields to your point is this a safe run rate look at ahead of just kind of looking at where the basis goes from here.

Yes, I'll answer it like this that we've seen spreads fall to 25.

25, 30 <unk> as of recently, we do believe and I believe the industry believes that over the next year and a half to two years is that we will start moving back out we may see 75 cents or a dollar we have some of our competitors out there talking about building and maybe another 42 inch what we're trying to tell the marketplace and the producers and shippers before they commit another.

Jack will have capacity, we have capacity coming available in two or three years from now.

And we'd love to lock it in for prices similar to what they would pay on Newbuild on Greenfield projects. So we are very well positioned to kind of weather. The storm here is all the.

Two inches had been completed as the gas begins to grow and fill them up.

They all become comfortable we're very well positioned to capture a bigger spread on capacity. It will have on our on our gas system.

Got it and maybe just a little bit more of a niche topic here the legacy PBR assets Youll still have any exposure there in terms of.

What we're seeing on price hikes in the coal market right now or Alternatively is this a more attractive seller's market, where you might look to divest some of those legacy assets.

No I wouldn't say that there.

And then there would be any any opportunity for for a spike there as you know that's a very small very very small piece.

Sits up there, it's a royalty to royalty business. So I wouldn't guide you towards anything there as far as divestiture.

There is no plans no no dialogue going on in that front.

Got it thank you.

Our next question is from Michael Blum with Wells Fargo.

Hi, Thanks.

Good afternoon, everyone.

I wanted to ask about Rover.

I know you highlighted by a $13 million increase in revenue just wanted to hear what the dynamics are on Rover right now how much of that is contracted and I guess given that duration is pretty tight on takeaway is there an ability to sign up.

More producers it at higher rates.

Yeah, Hi, Michael this is mackie.

What a great project that hey, that's really turned out well for us.

We saw for example, we saw hiccup on Pepco pipeline here, a couple of months ago.

All the value of that pipeline increase even more so with the difficulty that we see in the at least the near term over the next two to 345 years, how difficult it will be to get another interstate pop unapproved out of that area, but we're still well positioned.

We do have.

Probably approximately over 90% of it under long term contracts.

On a month to month basis, many times, we're selling capacity at tariff rate, depending on the month, depending on whether theyre going to dawn or are going south of <unk>.

It's such a excellently strategically located assets as we see volumes grow out of Marcellus Utica.

It's kind of unique in the sense. They can move barrels up north into Canada, and as you know it can move barrels all the way down to the Gulf coast to provide supplies for LNG facilities as well other marks on the Gulf Coast.

We.

Consistently move about three 2% to $3 four we can move as much as three point.

Five five I believe it is.

So we will continue to stay that kind of grow both in filling it up to the Max and also.

Max tariff rate.

As the future as we go into the future.

Got it and then just a quick follow up for me.

So your Capex for 'twenty, two 'twenty three of that $5 million to $700 million per year range.

I'm, assuming that does not.

Does not include any potential spending on these initiatives you have going on in Panama.

My question is if if this mou becomes an RFID project.

Panama, how does that change those numbers.

It would certainly add to those numbers, but getting that project to <unk>. It's down the road, we're probably talking at least 12 months to get that.

So we would see any material spending until probably 'twenty three.

Got it thank you.

Our next question is from Pearce Hammond with Piper Sandler.

Yes, good afternoon, and thanks for taking my question I just had one question today Mackie as you look out over the next few years.

GL supply demand when do you see a need for more fractionation capacity at Mont Belvieu.

Well, what a great question and we are positioned to capitalize on that when we find the answer that question.

Very capital disciplined, but we have not completed our eighth frac, but we're certainly watching it very closely both for volumes that are committed to our plan.

Also volumes committed to third party plants, so just from a.

Looking from our eyes and Retrans for US, we don't see the need for one for at least the next.

Six to nine months, but we evaluate on a quarterly basis and we do expect that at some point in 2022, we'll have to take a serious look at completing that eight frac because we do expect the volumes to begin growing.

As long as commodity prices continue to stay where they are now and ensure it looks like they will.

Thank you Mackie.

Our next question is from Christine Cho with Barclays.

Hi, everyone. Thanks for squeezing me in.

I just wanted to how should we think about costs going up in 'twenty two.

O&M and G&A side.

And then to your inflation trackers.

Have any cash to them and to the extent that it tracks something like a CPI or PPI should we think that should we assume the entire increase will be reflected in rates next year or what competitive pressures limit some of that the increase that you would actually material.

I can start on the second half of that which maybe most of it.

And most of our contracts certainly in all of our liquid contracts around our transportation and fractionation and around our crude contracts. We have an index. It's typically typically a FERC index, but to give you. An example, I believe the FERC index. This year I believe starting in July and goes July to the next July was negative.

So we actually didn't have any.

Any kind of uptick in that.

Contracts as well as in many if not most of our gas contracts. So we do have whether it's the CPI index a gas contract for the FERC index and our liquid contracts. We do have that in the majority of those who will benefit from.

Or at least not be harmed by that.

The inflationary growth.

And cost.

And we should.

I expect that you would see the entire increase through.

If pressures wood and wood.

Precludes you from just doing a part of it.

It may on future contracts, but what I am referring probably with all the existing contracts we have today to move products through our systems already have that language in it okay.

And then on the NGL segment just curious.

One of your peers had talked about.

Doing incentive rates in the Permian curing.

Curious if you guys did the same thing or if the segment was really just all optimization headwinds.

Yeah.

Sure.

Kind of rate is the rate we will do is the highest rate we can possibly get from our shippers.

From what the market will allow.

Oh.

Well I guess would you say, they trended lower quarter over quarter.

Oh, I'm, sorry, so you're saying, it's kind of what are the marketplaces, yes.

Just like crude just like natural gas per liter or a short period of time NGL across all has been overbuilt. Fortunately much of the barrels that are that come to our system and they will come to our system in the future already dedicated but those barrels that are out there at the tailgate of third party third party facilities.

Go out and try to get on a monthly basis, it's gotten very competitive.

The TNF prices are significantly lower than where they were years ago.

Got it thank you.

Our next question is from Michael <unk> with Goldman Sachs.

Hey, guys. Thanks for taking my question look we're eight or nine months removed from winter storm. Yuri can you can you give a little insight on what youre seeing in the contracting market for gas storage, especially in Texas, whether you're already entering significant new contracts and kind of taken a little bit of maybe the margin upside but also.

The margin downside of spreads move around but getting more of a fixed fee payment and just kind of how the market for gas storage overall is moving after that event.

You bet. This is mackie again.

Yes, it's kind of a variety we effected a lot more demand or a lot more desperate I'd say demand to come and secure storage. We certainly have more storage than we did last year at much more favorable rates and also some swing right through that.

We are still in negotiations with a number of parties and power plant.

We're swinging start with the service and storage service for this winter, but some of the companies had panicked or habit.

Don't seem as worried about it as we thought they would have to what happened at Uri, but once again, we're well positioned whether or not we've already done as we have some new deals or we're positioned to be able to provide that service as they need it this winter.

Got it. Thank you guys much appreciate it.

Ladies and gentlemen, we have reached the end of the question and answer session.

Like to turn the call back to Tom long for closing remarks.

Thank you all once again for joining us today and for your support and we look forward to talking to you in the near future.

This concludes today's conference energy transfer. Thanks, you for your participation you may disconnect your lines at this time.

Q3 2021 Energy Transfer LP Earnings Call

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