Enterprise Products Partners L.P.

and welcome to the Enterprise Products Partners third quarter 2021 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you may please press star 1 on your touchtone telephone. It is my pleasure to introduce your host for today's call, Randy Burkhalter, Vice President of Investor Relations. Thank you. You may begin.

Thank you, Julianne. Good morning and welcome, everyone, to the Enterprise Products Partners conference call to discuss third quarter earnings. Sorry and apologize for the delay, but we're ready to go now. Our speakers today will be Co-Chief Executive Officers of Enterprise's General Partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934, based on the beliefs of the company, as well as assumptions made by and information currently available in the enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I'll turn it over to you, Jim. Thank you, Randy.

Our businesses continue to perform extremely well during the third quarter. We reported $2 billion of EBITDA, even though we were impacted by $30 million of headwinds due to Hurricane Ida. Cash flow from operations was a record $2.4 billion, which more than fully funded both our capital expenditures and our distributions. Year-to-date cash Distributable cash flows, almost $5 billion, which has provided coverage of 1.7 times and $2 billion in retained cash year-to-date. As we head into the final quarter of the year, while we don't take anything for granted, it looks like our businesses are going to finish with another strong year in 2021. Our results reflect the ongoing recovery in demand for crude, NGLs, primary petrochemicals, and refined products, as the global economy continues to recover. For 2022, most experts agree on continued strong demand and economic growth worldwide. We believe that economic backdrop, plus the need to restart virtually everything, will continue to provide strong demand growth for oil and gas, natural gas liquids, and plastics. In addition to the record cash flow from operations, we had record profits from our propylene business, which contributed to the record gross operating income for our petrochemical and refined products services sector. Our PDH and splitters complement one another in our value chain, and we were able to take advantage of strong propylene spreads. Long-term, petrochemical fundamentals are very strong, and U.S. petrochemicals have multiple competitive advantages compared to almost all of their global peers. Likewise, Enterprise remains strongly positioned to provide the petrochemicals midstream services, including feedstock, storage, distribution, and exports. It's a footprint that's not easily copied. Our liquids pipelines have substantially recovered to near pre-pandemic levels, at 6.3 million barrels a day with gas processing volumes benefiting from higher prices for NGLs. Enterprise's natural gas pipeline transportation for the third quarter exceeded pre-pandemic 2019 levels at a record 14.6 BCF a day. In total, our crude oil equivalent pipeline transportation volumes were 10.1 million barrels a day for the quarter. NGL fractionation volumes remained supported at 1.3 million barrels a day. Our propylene production for the third quarter of 2021 was 96,000 barrels a day. Liquid volumes handled by our marine terminals for the third quarter were 1.5 million barrels a day. We completed construction of approximately 480 million of organic growth projects. These projects are in varying stages of startup. The major projects include a natural gasoline hydrotreater, which reduces sulfur content in blend stocks used for motor gasoline, and several petrochemical pipelines and natural gas pipelines that expand those integrated systems. We expect to complete the Acadian, Hainesville, and Gillis lateral natural gas pipeline expansions in the fourth quarter of 2021. Our Acadian-Hainesville gas pipelines are strategically located to move growing Hainesville and Cotton Valley natural gas supplies to growing and higher valued industrial and LNG markets. We have developed an impactful project to utilize hydrogen as a fuel at our PDH2 plant. This project will provide significant environmental benefits as well as upgrade the coproduct value of produced hydrogen. The change involves adding the capability to utilize hydrogen produced by the facility as fuel rather than relying on natural gas. By modifying the design of the heaters for PDH-2, we will reduce the plant's absolute carbon equivalent emissions by almost 90%. construction of PDH-2 remains on schedule and on budget, with completion expected in the second quarter of 2023. We became very bullish on hydrocarbon prices on April 20, 2020, and at $80 a barrel, crude oil has increased in excess of $30 since the beginning of the year, and propane and natural gas prices have doubled since the first of the year. U.S. oil and gas industry is now in the hands of highly disciplined parties. We like to believe they prefer doing business with large and similarly responsible companies like us. But now crude oil pricing remains on a path that is dictated by OPEC+, who need to receive higher prices for their products in order to balance their budgets and improve their economy. Clearly, they don't seem to be interested in any more price wars. OPEC's also signaling that they believe the world is going to need every barrel we can get our hands on in the future, including U.S. shales. We believe natural gas now has a sustained price of $3 plus in order to encourage non-associated production in places like the Hainesville and the Lane-Eagleford. Likewise, we believe that all signs point to some level of staying power for the stronger price to WPTI ratios we're seeing for propane and butane. Over the last 10 years, we've seen significant growth in global demand for U.S. liquids because of their price transparency, environmental attributes, and transportability. We're very proud of what has evolved into a hydrocarbon franchise that has a strong domestic presence and a global reach. And with that, Randy, it's yours.

Okay. Thank you, Jim. Good morning, everyone. In looking at the income statement, net income attributable to common unit holders for the third quarter of 2021 was $1.2 billion, or 52 cents per common unit on a fully diluted basis. This compares to $1.1 billion, or 48 cents per common unit on a fully diluted basis for the third quarter of 2020. Net income was reduced by non-cash asset impairment charges of $29 million, or one cent per unit, for the third quarter of this year, and this compares to a charge of $77 million, or three cents per unit, for the third quarter of last year. Moving on to cash flows, cash flows from operations was $2.4 billion for the third quarter of 2021. This compares to $1.1 billion. for the third quarter of last year. It should be noted that the third quarter of 2021 cash flow from operations benefited by $648 million of net cash provided by changes in working capital accounts. The swing in cash provided by or used for working capital accounts between the two quarters accounts for substantially all of the $1.3 billion favorable variance between the two quarters. Free cash flow for the 12 months ended September 30, 2021, which is cash flow from operations, less investing activities, less net cash flow to non-controlling interests or JV partners. was $5.6 billion compared to $2.1 billion for the comparable trailing 12 months in 2020. We declared a distribution of 45 cents per unit with respect to the third quarter of 2021 to be paid on November 12th. This distribution of approximately $1 billion for the quarter represents a 1.1% increase compared to the third quarter of 2020. During the third quarter, we repurchased approximately $75 million or 3.4 million EPD common units. In addition to these buybacks, EPD's distribution reinvestment plan and employee unit purchase plan purchased a combined $36 million or approximately 1.6 million EPD common units in the open market during the third quarter. Our pray-out ratio, which we define as the sum of cash distributions and buybacks as a percent of cash flow from our operations for the 12 months ending September 30, 2021, as reported, was 51% and was 58% after adjusting cash flow from operations for cash provided by working capital changes. This is consistent with the 55% to 80% payout ratio we have maintained over the past decade throughout volatile business cycles and the pandemic. We are in the middle of our planning process for the 2022 budget. Our priorities for capital allocation are an all-of-the-above approach with a goal to facilitate the long-term financial health of the partnership. Our first priority is supporting and growing distributions to investors and Secondly, to support investments that complement our midstream system that have attractive rates of return in excess of our cost of capital with the objective of growing the partnership's cash flow per unit. Next is to maintain financial flexibility that enables us to weather business cycles and evolving legislative and regulatory risks to the energy sector. Finally, it will be to execute BIPACs on an opportunistic basis. As we have for the past several years, we plan to announce distribution growth guidance for 2022 in January. During the quarter, we issued $1 billion of senior notes at a fixed rate coupon of 3.3%, with the net proceeds to be used for general company purposes, including the repayment of our $750 million, 3.5% senior notes, and our $650 million of 4.05% senior notes that mature in February 2022. We elected to issue during the third quarter rather than refinancing in 2022 to avoid interest rate risk. We were able to extend these maturities by 30 years while reducing the the coupon of the debt by almost a half of a percentage point. We would like to thank our fixed income investors for their continued support as this offering had over $4 billion of demand on the busiest issuance day of the year. During the quarter, we also renewed our 364-day and multi-year revolving credit facilities in September. In addition to extending the tenor of these facilities, we proactively decided to reduce the overall size of the multiyear facility by $500 million to $3.0 billion. Together with our $1.5 billion 364-day facility, we have $4.5 billion of borrowing capacity under these facilities. Over the past two years, we have proactively reduced enterprises' bank credit commitments by a total of $1.5 billion, or 25%. This has principally been in response to our lower level of expected capital expenditures, while also trying to be a responsible client to our bank, many of whom have been under investor pressure to reduce capital commitments to the traditional energy industry. Our total debt principal outstanding was $29.8 billion as of September 30, 2021. Assuming the first call date or the final maturity date for our hybrids, the average life of our debt portfolio is 16.8 years and 20.9 years, respectively. Our effective average cost of debt is 4.4%. Our consolidated liquidity was approximately $6.7 billion at September 30, 2021, which includes availability under our bank credit facilities and approximately $2.2 billion of unrestricted cash on hand. This amount of cash on hand, while elevated by historical standards, is primarily due to having already completed our refinancing and having cash available to retire $1.4 billion of senior notes in the first quarter of next year. It also provides us additional flexibility to respond to market opportunities. Adjusted EBITDA for the third quarter of 2021 was $2 billion and $8.3 billion for the 12 months ending September 30, 2021. Our consolidated leverage ratio was 3.2 times after adjusting debt for the partial equity treatment of the hybrid debt securities and reduced by the partnership's unrestricted cash on hand. With that, Randy, we can open it up for questions.

Thank you, Randy. Dylan, we're ready to take questions from our listeners, and I would remind our listeners that we'd like to keep our questions to one question and one follow-up. Thank you. Go ahead, Dylan.

Thank you, sir. As a reminder, to ask a question, you would need to press star 1 on your telephone. To withdraw your question, please press the pound key. Due to the absence of time, we ask that you please limit yourselves to two questions or one question and one follow-up. Please stand by while we compile the Q&A roster. I show our first question. It comes from the line of Schneir Krishuni from UBS. Please go ahead.

Hi. Good morning, everyone. I was wondering if you can share your latest thoughts around potentially accelerating return of capital in You know, many of your peers are pursuing buybacks. Some have announced special increases and so forth. We're seeing positive stock reactions. A lot of the producer customers are electing to pursue buybacks instead of investing in growth. And so, you know, kind of wondering about your latest thoughts. In the past, you've mentioned some uncertainty with respect to Washington, but there's now a draft reconciliation bill out. Has that thought process changed at all? And if so, is there a preference towards buyback given where the stock is trading? or would you be thinking about base distribution increases or special distribution increases?

Okay. I appreciate the question this morning. You know, as was stated in prepared remarks, I think when we think about allocation of capital, it's an all-of-the-above approach. You know, we have been deliberate on buybacks, and You know, and some of that is because of the legislative and regulatory uncertainty. And, you know, as far as looking out, we're still working. You may see clarity in Washington, D.C. We don't. And, you know, I think we'll come in and get better clarity over the next few months. You know, on the... buyback activity that you mentioned from, I guess, you were referring to Magellan and MPLX. I think we need a little bit more time to see market reaction to that. There were a couple of research notes that we saw was where, what was it, during the time period that they did buybacks that Magellan actually underperformed in that August and September period during the point in time when they actually did buybacks, and then since the time they announced all those buybacks, they had pretty much performed in line with others. So I don't think we're ready to make a knee-jerk reaction to their performance or the outperformance as a result of the buyback. I would also note If we go back and look at several years, we're allocating a good bit of cash. In fact, we're one of the highest in paying out returning capital to our investors. And, again, that's principally through distributions. Magellan has come in. I'll note Magellan has come in in the last year and really increased their payout ratio significantly. but a lot of that has been as a result of proceeds from asset sales that they've been returning to investors, which makes sense. But if you've noticed, we've just not had much in the way of proceeds to asset sales. So we'll be coming in. We're going through our 2020 budget cycle. We'll come in and announce what our plans are for distribution increase next year. in January. You know, I would note that 2021 marks our 23rd year of distribution growth. I don't think any other midstream company can say that. And so, you know, it's our practice to return capital to investors, and that includes both distributions and buybacks. But we'll come in, and we need to go through our budget cycle to come in and provide any more clarity on that.

You did a pretty good job in your script laying out the priorities we look at, right? Right.

Okay. I appreciate the color. I guess I was thinking along the lines of that you've got a $4 billion annual distribution and that if you reduce the unit count that it would actually fund more distribution growth in the future. But I guess we'll wait and see for the next update. Maybe pivoting a little bit here, your CapEx growth range for next year, you sort of tighten the range and you sort of seem to have a $1.5 billion cap, I guess, for next year. Is that the winnowing process of some prospects dropping off? Have some ideas dropped off the table? Or is it a function of producers continuing to remain disciplined on production and more focused on buybacks? Just kind of wondering on the tightening of the range there.

Yeah, Shanier, on that, not anything has dropped off the table as far as projects under development that really that we've been referring to for the first nine months of this year. It's more just from a standpoint of maybe timing of when some of those capital expenditures would hit in 2022.

Okay, so at the end of the day, the high end right now you're looking at is $1.5 billion for growth capex.

Shanier, as we sit here today on November 2nd, Our best estimate for growth capex in 2022 is $1 to $1.5 billion. That will be subject to change as we get into, you know, as things develop.

All right, perfect. Really appreciate the callers tonight. Thank you.

Thank you. I see our next question comes from the line of Jeremy Tomet from J.P. Morgan. Please go ahead.

Hi, good morning. I just wanted to start off with the Build Back Better bill and just see if it is passed as it's written today, how that might impact enterprise going forward, be it the higher 45Q levels, be it including renewables. Just wondering what impacts that could have on your business if it is passed.

Yeah. Jeremy, again, you guys in New York must have a better visibility to D.C. than what we see. Because, I mean, from what we've seen, the Build Back Better plan is still in a great deal of flux. And statements that have come out of the Senate, especially Senate Finance Committee, it sounds like they are still pursuing some proposals there So I think everything is really still very much in a state of flux. So from the standpoint of first in Senate Finance Committee, you've got where they were looking to eliminate oil and gas tax preference items, which again includes the qualified earnings for MLPs attributable to fossil fuels. The counter to that is out of the house ways and means where you have – they do not have the provision to eliminate the oil and gas tax preference items, which, again, are intangible drilling costs, cost depletion, and MLPs. And, in fact, they actually expand the qualified business activities for MLPs to pick up some renewable activities. Um, and you know, you've got some saying that the legislation is going to go from the house to the Senate, but then we're hearing that also in the Senate that they want to start in the Senate and move to the house. So I, um, again, you guys in, in on the East coast might have better, better visibility, but that's, that's sort of the last thing we see. Uh, as far as on the 45 Q credits, it is encouraging that, um, that they are looking to come in and increase the amount of credits. I think in order to come in and get carbon sequestration, whether it's sequestration or whether it's through EOR, I think the credits do need to be higher. It's also encouraging to see a direct pay be included in that as well. But I think right now anything we would comment on would really just be pure speculation based on where the legislation is currently.

Okay. Maybe just taking a step back, just curious, I guess, you know, Enterprise in past years has been kind of a top performer in the space. This year has not as much. Just wondering what you think could be the driver of the relative performance this year, and could anything be kind of changed going forward to help that out?

You answer that one.

Yeah. Jeremy, I've From a business standpoint, we're putting up good numbers. I would go back and we think we're doing our part as far as returns on capital, the cash flow that we're generating, the performance that we're recording throughout business cycles. As I said on the last call, when we come back in and look at probably our highest correlation is to the S&P energy sector. And I think that's the comp that we track most closely as far as coming in and comparing to various midstream companies. Hard to say. Every dog has its day. And we're going to continue to execute on what we're doing well. And, you know, our allocation to capital strategy is going to be all of the above.

And we just keep doing one board seven times coverage, keep retaining a lot of cash, and sooner or later it pays off.

Got it. I'll leave it there. Thank you.

Thank you. I show our next question comes from the line of Janann Salisbury from Bernstein. Please go ahead.

Hi, good morning. In the release, you note that your major Permian and Rockies NGL pipelines were down 31 million versus 3Q 2020 due to lower fees and volumes. Can you expand on what's happening? I had thought that NGL pipelines were kind of relatively safe from rate competition. And I'm not clear also if that 31 million is related to the Hurricane Ida impacts that you referenced.

Gene Ann, this is Brent. There's volumes in the Rockies that continue to decline. We started to see a little bit of rig activity up there, but for the most part, volumes are declining. Also, the fee structure up there has declined in the third quarter. In terms of the Permian, we offered some incentive rates in the short term on transportation to help entice volumes. And then, Tug, I'm looking at you on impacts from the hurricane. I don't think we had any impacts from the hurricane as it relates to MAPL.

Okay. Thank you. That's helpful. And my follow-up is on the Texas interest date. Kind of a similar question. There was a $34 million decrease from 3Q20 based on lower capacity reservations. I think that makes sense because overall utilization on gas pipelines, Whistler kind of started, but it feels like it should improve from here. There's no more new pipelines coming. Is that kind of what you're seeing as well, or do you think that you could see Texas Interstate go lower in the next few quarters if more contracts roll?

I think going forward, Gina, you're going to see those volumes increase and those margins get better.

Okay, that makes sense. And then I guess just like quickly following up on what you said about, sorry, the answer to my first question about the incentive rates from the Permian. Is that like a competitive situation, I guess, where that plant has multiple pipelines and you're trying to get them to use enterprises instead of a third party?

That's it. At the end of the day, if we can cover our costs and make some money, that's what we're going to do. But ultimately, a lot of these processing plants in the Permian, it's a very efficient market, and we just have to compete harder.

Great. That's all for me. Thanks a lot.

Thank you. I show our next question comes from the line of Chase Mulvihill from Bank of America. Please go ahead.

Hey, good morning, everybody. I guess the first thing I wanted to follow up on was the propylene business. You know, gross margin was pretty strong coming in at $260 million, and this was despite the 34 days of unplanned downtime on PDH-1. So I guess maybe could you just talk to that a little bit, what drove that, and then how sustainable on a go-forward basis do you think this $260 million gross operating margin number is?

Chris, you want to take it?

Sure. Hi, Chase. This is Chris Dana. Overall, we have several, actually a significant number of contracts that are structured in a way that it's a fixed fee, but when the spread blows out, we participate. So a lot of what you saw this quarter, is some of that benefit. And as to sustainability, I think you just look at the global supply chain issues across many industries. And when that gets solved, maybe we return back to some normalcy and spreads. But until then, I think we'll continue to see widespreads.

Okay. All right. I'm going to follow up just kind of thinking about ethylene and LPG exports, you know, as we kind of move into 2022, you know, kind of what underlying trends are you seeing today and, you know, what do you expect to see in the 2022 for LPG and ethylene exports?

Did you say ethylene or ethylene or both? I'm sorry, ethylene.

Well, you can talk to both if you want to. I'll slide that in there as well.

Justin and then Chris.

Yeah, Chase, this is Justin Kleiderer. With respect to ethane and LPG, I mean, ethane is probably more of a domestic story versus LPG, but I think both the case remains, which is demand will continue to outstrip the pace of supply growth as we forecast it. So we feel good about our LPG export dock continuing to remain full regardless of how it's contracted today, and we continue to feel good about ethane prices as a whole because domestically we still think demand is going to outstrip supply.

And how full are you on ethylene exports right now?

November should be a record month.

Okay. Chris, ethylene?

Yeah, the same for ethylene. November is going to be a record month for us. And we're 95% contracted to the nameplate, but we've demonstrated we can run much higher than the nameplate.

All right. Perfect. Appreciate the call. I'll turn it back over.

Thank you. I show our next question. It comes from the line of Keith Stanley from Wolf Research. Please go ahead.

Hi. Good morning. I think I recall there might have been, just following up on Propylene, there might have been a local press article saying the company was considering adding another splitter. Is that something you'd be exploring with the market conditions very strong and I guess, how do you think about the economics for that? And then, relatedly, the potential upside to CapEx for next year, going to $1 billion to $1.5 billion, is that tied to a particular chunky project or several smaller ones?

As far as a splitter, I think some of the projects we're working on that we haven't finalized will dictate whether we look at another splitter. Anything on that, Chris?

No, and Graham can comment on this, but we have a pretty standard process for projects, and the tax piece is the first step of that, so that's probably what you saw in the press.

What was the rest of the question? The 1 to 1 side. I think we're working on it. Randy said we're working on some projects that... If they come about, we could see a little bit of an upturn in that CapEx. Right, Todd?

That's right. Yeah, and Keith, that's just not one chunky project. That's several projects.

Okay. Okay. Got it. Thank you. And then just a clarification question on the special distribution concept, which you referenced MPLX. I don't think Randy, that was in your list of options, but is a special distribution something you would think about and consider next year if you had excess cash and just how you think about that versus buybacks? I'm assuming it's more efficient in your view to do a special if that was an option.

Keith, I think our focus would really be more on regular way increasing the base distribution. and then we'll see what we do on buybacks. And the buybacks obviously will depend on, you know, opportunistic buybacks, market conditions, and also business opportunities at the time. Thank you.

Thank you. I show our next question. It comes from the line of Michael Bloom from Wells Fargo. Please go ahead.

Thanks. Good morning, everyone. I just want to talk a little bit about the Haynesville. You've seen a little bit of an uptick in your systems around there. I wonder if you can just give us an idea of if you're seeing increased producer activity there, what's sort of driving the uptick in volumes on those systems?

You want to take it?

Yeah. So we're seeing increased activity from our existing producer customers, but Not only that, we're seeing new opportunities arise from potential new customers, some hitting the Cotton Valley, but all from a gathering, treating, and processing perspective. I'd say we're working on a project to expand the Cadian one more time, adding 400 million a day. So by the time that's done, Gillis will add 1.025 BCF a day, take away to LNG markets, and then we'll add another 400 of acadian capacity after that.

Got it. That's helpful. And then you have an interesting announcement around hydrogen for PDH2. Just curious, is it feasible to look at PDH1 and try to retrofit it effectively for the same hydrogen application, or is that not possible?

Graham or Angie? Just Graham. I'll take that. I think to a limited extent we can, but the technology lends itself better to the technology we've used for PDH-2. There's a lot more technical hurdles to overcome on PDH-1.

What about other plants that your contracts roll off, Graham?

I think we've got other opportunities where our contracts roll off and we've got optionality on how we look at hydrogen versus the market, how we consume and As well as the consumers in the facility, there's some options there. Some of the other units that are probably more suited to hydrogen than maybe even PDH-1. We're taking a look at all of those right now.

Michael, we've been selling our hydrogen. What I think Graham's saying is as those contracts roll off, there ought to be other opportunities for us to use that hydrogen.

You've got that option. We've got that option to the market or internally.

Got it. Thank you.

Thank you. I see our next question comes from the line of Michael Cusimano from Pickering and Partners. Please go ahead.

Hey, good morning. Thanks for taking my questions. So, the press release mentioned lower NGL marketing activities as an impact of hedging. I was hoping you could talk about the significance of those hedges as well as how would it affect 4Q and then moving into 22.

I think in terms of the margins on NGLs, it's more a function of contango storage plays that we had in the past. And in terms of the hedging aspect, Justin?

Yeah, I think any hedges you see there will be realized when physical delivery of product is made. So I would view those as transitory. And I think to Brent's point, you know, the second half of 2020 saw significant changes. stored revenue as a function of April of 2020 and COVID.

Okay, so it's less of a function. There's not much like NGL equity exposure that you've hedged away that would be impacting that?

We have very little processing exposure hedged.

Okay, thank you. And then staying on the NGL segment, it looks like the Ethylene rejection from higher natural gas prices negatively affected the NGL segment, like looking quarter to quarter. Can you talk about what you're seeing today relative to 3Q, and then also if that rejection in the NGL segment improved what you saw in the natural gas segment for 3Q?

I think in terms of what we see going forward, so you're accurate in terms of the rejection that was going on within our system. In terms of going forward, we're going to have to watch to see how fast producers get back, but I think ultimately it comes a point in time, and we'll see when it happens, where the demand of the petrochemical sector is going to outstrip supply. We'll see how far away it has to be to get recovered from places that aren't nearly as close to the Gulf Coast as Permian or the Eagle Ferg or Haynesville or some areas like that. I think that answers your question.

All right. Thank you. Appreciate it.

Thank you. I show our next question comes from the line of Eve Segal from Segal Asset Management. Thank you. Please go ahead.

Yeah.

Hey, good morning, everybody. I just have two questions. I guess I'm only allowed two questions, but, um, you know, in terms of growth going forward, uh, and capital expenditures going forward, you know, what, what, what, what are the areas that excite you, uh, in terms of, uh, the opportunity set and could, you know, MNA be part of that? Um, so that's one. And then the second is, uh, on inflation. Um, and Randy, my crystal ball is pretty, pretty bad. But to the extent that we see inflation, what's the philosophy around the distribution regarding inflation? And are you focusing any inflationary pressures in the business right now?

Take the first one, Randy. You take the second one. In terms of some of the things we would like to do, Eves, is we've been pretty good at repurposing pipelines. So you can probably assume that we're looking at repurposing pipelines. And as far as M&A, I love what Randy has said all along. Where M&A is concerned, price matters, and we kick a lot of tires. And if the right price comes along, we're probably going to take a look at it.

Can I just interrupt right there? Has there been a subtle shift in terms of – how you think about M&A? And I get what you said about price, but strategically, is M&A becoming a little bit more interesting to you?

I don't think anything's changed, Eves. By the way, that's your second question. I don't think anything's changed. I think maybe some valuations are a little more... are a little better, and that's what price matters means.

Yeah, and Neve's going to, I guess, what is now your third question. On inflation, I want to say over 90% of our revenues have some sort of escalation mechanism in there, which are benchmarked to various indices. So we feel like we have pretty good protection from inflation. I think Graham and his team have done a great job on our capital projects. As far as on long lead items, we've really been in pretty good shape as far as not seeing cost creep on those projects. As far as how we think about the distribution, we said really very What we're trying to achieve is trying to keep to, what is it, purchase power parity. And so we would like to come in and, with the increase in inflation, have an increase in the distribution growth rate compared to what you've seen over the last three or four years. You know, and really, if I could use this just in terms of that, and this might get back to Jeremy's question of... as far as recognition of the progress we've made and not showing up in the unit price. Some of it may be, you know, what have you done for me lately? And we came in and we shifted our posture in 2017 to come in and be able to finance the business better rather than coming in and relying on both the debt and equity capital markets. I think we were the first mover in coming in and self-financing the business. At first it was providing our own sources of equity capital, and this year our cash flow from operations is going to cover all of our capex. So I think we made that shift, and to a degree it may come down to a long-term view and maybe because the feedback that we get from our long-term investors, they are quite pleased with what we've been doing versus short-term. And I think a good bit of the liquidity in the stock market these days is high-velocity, short-term-oriented money, which may not align with how we've been allocating capital over the last couple of years. But we think the way that we're progressing here, is best for the long-term financial health of the partnership. We've been, you know, I go back. During this time period, you had a lot of MLPs, 150-plus, come in and cut distributions, and we did not. So as a result, you know, they actually – decreased the amount of capital they returned to their partners over the last three or four years while we continued to increase ours. But now we're at a position of what have you done for me lately? You know, you've got some people that may have a little bit more beta and short-term gains that they can do because they cut their distribution so deeply. So, again, we're running a long race here. We're mindful of returning capital. Again, we're going to come in and do the all of the above approach. But that's sort of a follow-up on Jeremy's questions. Without charging you an extra question, Jeremy.

I got caught.

Thank you. Thank you. I show our next question comes from the line of Colton Bean from Tudor Pickering Holt. Please go ahead.

Morning. So a couple of follow-ups here. Following up on the $1 to $1.5 billion range, can you clarify what level of spin was contemplated for SPOT, or was that not one of the development projects in there?

That's not in that number.

Got it. So that would be incremental to the range?

Yes.

Understood. And then maybe circling back to NGL marketing, you know, can appreciate on a year-over-year basis the impacts of Contango, but I think on a sequential basis, it also looked like there was a pretty material step down. So just trying to better understand, you know, what changed from Q2 to Q3 in the NGL marketing business, and then, again, what the expectations are as we move towards the year-end in 2022.

Yeah, Colton, this is Justin Clyder. I mean, I could sum it up pretty simply. It's just timing of spread capture, and that's going to change based upon markets.

Okay. And, Mitt, I'll slip in a final one here. Brent, you talked on or touched on, you know, how far away FAA might need to be pulled from. I guess as you look across your system, whether it's ATEX or MAPL, are there any opportunities that you all see from increased extraction?

I think there's Rocky's volumes, ATEX to some extent. There's not a whole lot of capacity left on there, but we do have some. And then ultimately, I think the bulk of the volume could come from the Permian, the stuff that's being rejected up there currently.

Great. Thank you.

Thank you. I'm sure our last question comes from the line of Michael Lupides from Goldman Sachs. Please go ahead.

Hey, guys, thanks for answering all these questions, and congrats on a decent quarter. Real quick, just curious how you're thinking about the battle between Corpus and Houston for crude export volumes. Obviously, export volumes have been pretty weak for the last couple of months, but just curious how you're thinking about the share over the next quarter or so, and maybe even over the next 12 to 18 months.

I don't know about the next quarter. I think ultimately it becomes a battle between Corpus and Spot. Brent?

To me, what's going on is something that we have preached for a long time about Houston being a market and Corpus being a destination. I know some people get tired of hearing that, but I don't think in terms of the export business they want. I think it's just a function of where the pipelines end up and what they have to do. Ultimately, the value of the barrel is worth more domestically than it is across the water. So that's what you're seeing go on in Houston with, frankly, we've got customers that have take-or-pay contracts, and ultimately what they net back is quite a bit higher domestically across our system in the Gulf Coast. Where we want to be long-term is going across the VLCC dock, and ultimately over time we think then spot and pull the barrels away that want to go to the export markets.

Got it. Thank you, guys. Much appreciated.

Okay, thank you. And, Dylan, we're ready for you to give our listeners the replay information, if you don't mind. And I'd like to thank our participants for joining us today, and we're going to go ahead and go offline if you'd give them that information. Thank you. Thank you, sir.

This concludes today's conference call. The replay will be available from 1 p.m. Eastern Time, November 2, 2021, to 1259 p.m. Eastern Time, November 9th, 2021, please dial 1-855-859-2056 or 404-537-3406 for international participants. Enter access code 478-3552. Thank you and have a wonderful day.