Ladies and gentlemen, thank you for standing by, and welcome to the Q4 2021 Enterprise Products Partners Conference Call. At this time all participants are on a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. [Operator Instructions] I would now like to turn the conference over to your speaker for today, Randy Burkhalter, Vice President, Investor Relations. You may begin.

Thank you, DeWanda. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss fourth quarter and year-end 2021 earnings. 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 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 to 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 so, with that, I’ll turn it over to Jim now.

Thank you, Randy. We reported net income attributable to common unitholders for 2021 of $4.6 billion or $2.10 per unit compared to $3.8 billion or $1.71 per unit on a fully diluted basis for 2020. Cash flow from operations was $8.5 billion for ‘21 compared to $5.9 billion for 2020. Both ‘21 and ‘20 were impacted by large changes in the working capital and opposite directions brought about by significant storage opportunities. We generated $6.6 billion of DCF in ‘21 compared to $6.4 million in 2020. We had 1.7 times coverage. We retained $2.6 billion of DCF in ‘21 and head into ‘22 with significant financial flexibility. We also increased our distribution again in 2021 to $1.815 per common unit, making this the 23rd consecutive year of distribution growth since our IPO in 1998. In addition, 2021 marked another year of records for enterprise, including 12 financial records and five operating records. Our NGL Pipelines & Services and Natural Gas Pipelines & Services segments set gross operating margin records. We’ve also been focused on growing our Petrochemicals & Refined Products Services segment, which had a record gross operating margin of $1.4 billion for 2021 with a huge contribution in petrochemicals, where gross operating margin exceeded $1 billion for 2021. We set five operational performance records in ‘21, including record ethane marine volumes, record natural gas transportation volumes, record refined products and petrochemical transportation volumes, record propylene production volumes and record -- propylene production volumes. We also finished 2021 with a solid fourth quarter, reporting total gross operating margin of $2.1 billion. Our quarterly results were driven by another strong quarter from petrochemicals, our natural gas processing margins, an increase in equity NGL production, the continuing recovery in crude oil pipeline volumes to near pre-COVID levels and record natural gas pipeline…

All right. Thank you, Jim. Good morning. Starting with the fourth quarter income statement items. Net income attributable to common unitholders for the fourth quarter was $1 billion or $0.47 per unit on a fully diluted basis compared to $337 million or $0.15 per common unit on a fully diluted basis for the fourth quarter of last year. Net income was reduced by noncash asset impairment charges of $120 million or $0.05 per unit in the fourth quarter of 2021. This compares to $800 million or $0.36 per common unit for asset impairment charges of fourth quarter 2020. So, before the impairment charges, EPU was $0.52 per unit for 2021 compared to $0.51 per unit for 2020. Moving on to cash flows. Cash flow from operations was $2.1 billion for the fourth quarter of 2021 compared to $1.6 billion for the fourth quarter 2020. On a full year basis, cash flow from operations was $8.5 billion and $5.9 billion for 2021 and 2020, respectively. Cash flow from operations benefited from approximately $1.4 billion of net cash provided by changes in working capital accounts in 2021. By comparison, cash flow from operations was reduced by $768 million in 2020 due to changes in working capital. So if you would, a swing of $2.2 billion between the two years. Again, doing the math, cash flow from operations before changes in working capital was $7.1 billion for 2021 compared to $6.7 billion in 2020. Free cash flow for the year ended December 31, 2021, was $6.3 billion compared to $2.7 billion for 2020. Before cash provided by changes in working capital, free cash flow was $4.9 billion in 2021 compared to $3.4 billion in 2020. We declared a distribution of $0.465 per common unit with regard to the fourth quarter of 2021, which…

[Operator Instructions] Our first question comes from the line of Colton Bean with Tudor Pickering.

Good morning. So, now that you have the updated capital budget in hand, can you update us on how you’re evaluating your payout ratio for 2022? I think based on the budget today, it seems like the increase in free cash should outpace the distribution rates, but hoping to understand if Navitas funding would steer you to lower payout.

Colton, this is Randy. We’ve -- our payout ratio has really been averaging between 56% and 62% of cash flow from operations before working capital changes. And I think we’ll most likely be in that range in 2022.

Okay. And so, the Navitas acquisition, does that factor into the thinking?

Well, I mean, it is an allocation of capital for $3.25 billion that we’ll pay for. So, some of our -- as we mentioned, we’ll have some cash on hand after we’ve come in and pay this debt maturities in February. So, some of the cash would go towards the purchase price as well as borrowings on our bank credit facility.

And then just on the operational front, a significant step-up in frac unit margins relative to recent history. Can you expand a bit on what you’re seeing in that market and the sustainability of those margins in ‘22?

This is Zach. Some of that is a little bit of commodity exposure as the fracs have. So, there’s some blending margins. Some of that on the revenue side, we have a variable cost component. And so as gas prices go higher, you’re seeing our revenue go up, but our expenses are also going up.

Okay. And in terms of the operating expenses that -- it seems like that would have been backed out of the unit margins or the operating margin, but I just want to clarify that.

Yes. It should be. So, a lot of what you’re seeing on the increase is the commodity exposure on the blending margins. As far as frac margins as a fee base, there hasn’t been a significant change there, nor do we sort of see one in the near future.

But as gas prices go up, your frac fee goes up?

Correct. As gas prices go up, our fees go up, offset by some higher operational expenses.

Our next question comes from the line of Chase Mulvehill with Bank of America.

So, quick question. I guess, there’s growing concern when you think about the Permian and potential bottlenecks on the natural gas side as we kind of go through 2023. And so, I’d kind of be curious on some of your thoughts around this topic and kind of how this bottleneck potentially gets resolved. I mean, we’ve got, obviously, private E&Ps driving the majority of the growth, which makes it a little bit more difficult to sanction large greenfield projects just given that everybody is going to want 10-year take-or-pay contracts. And the private E&Ps may not be willing to kind of give that because they just don’t have 10 years of drilling inventory. So just kind of curious, your thoughts on kind of how you think this ultimately gets resolved.

You want to take it, Brent, or do you want me to?

Yes. This is Brent Secrest. It feels like a lot of the majors and the bigger publics out there are fairly well set in terms of the gas takeaway capacity. Most of the customers that we deal with and you can see our customer list, they seem like they’re in pretty good shape. So, when it comes to basis, in the past, the private guys have probably been the last ones to step up for capacity. And it’s benefited them in this environment from a crude perspective, from a gas perspective and some other things that they have had to and there was other people that stepped up to get projects done and to remove those type of basis dislocations. Ultimately, somebody is going to need to step up or a collection of people are going to need to step up. And every month that goes by without a gas pipeline being announced is just going to add to the problem. But there are certainly opportunities for us as Enterprise in terms of the capacity that we have remained open to participate in these types of dislocations. We talk to our customers about a potential for a pipeline project, but right now, we haven’t been able to get anything done on that side.

So, can I just follow up on this a bit and ask? I mean it seems like obviously somebody is going to have to take more risk, whether it’s the private E&P and whether it’s the person going to build the pipe and do not 10 years or 5 years or they’re probably not going to do, or is it going to be the gas processor. Like obviously, now you’re going to be the largest gas processor in the Permian. So, let me ask you the question. Are you willing to take more risk in the Permian on the gas processing side and maybe the contracts may have to be signed by the gas processor versus kind of the private E&P?

Yes. That’s just something in the past, we haven’t done Chase and it’s hard. I mean, there’s times where we step up for some last bit of remaining capacity that we can overperform from an operation standpoint, and we’ll take on a minute amount of risk. But ultimately the folks that are realizing $85 a barrel and the folks that are realizing gas prices at these levels and NGL prices at these levels, and terms of how we go pitch projects, those are the ones, that probably need to step up. Can we be complementary to it? Possibly, but to me, ultimately, this is about producers stepping up to get this project done.

Okay, perfect. Quick follow-up on ethane exports. During the quarter you averaged 171,000 barrels a day, and I think your dock capacity is 240,000 barrels a day. So, I don’t know if Justin’s there. I don’t know if somebody can kind of comment on where do you think you can take this, do you take it to the 240,000 barrels a day, or are there actually some constraints with vessels or imports on the other side, these docs that would present some constraints.

Hey, Chase. I think that as we think about dock capacity or ethane export capacity, we think 200 a day, maybe slightly above is a going run rate. But more often than not, when we start approaching those levels, those things that are outside of our system that start becoming constraints primarily around freight. So, it’s a milk run business and freight has to be there on a consistent basis for the units to be able to run at those rates. And more often than not, we don’t see that. Over time, we expect that market to get more mature for us to be able to get closer to the sustainable rates of 200, maybe slightly above.

So 240 is really your instantaneous, 200 is basically your operating.

That’s right.

Our next question comes from the line of Tristan Richardson with Truist Securities. Your line is open.

Hey. Good morning, guys. I appreciate your comments on Navitas and the opportunity in the Midland. I mean, should we think of that asset base as running pretty full today, and that’s driving the new plant investment? And then, should we think of a development schedule as planned activity by existing customers or maybe recent commercial wins with new customers?

We think that we -- I think everybody knows they’re bringing a new plan on as we speak. We understand they have plans for an additional plan. Frankly, I don’t think we know whether it’s what their existing customers or what their plans are. So, we haven’t dug in too deep going through this regulatory process.

Understood. And then just on the LPG side, you’ve talked about -- obviously, we saw substantial growth in total U.S. exports as part of the overall kind of global recovery. But recently, you guys have also noted that there’s a competing incremental domestic poll that’s emerged that may create one-off opportunities here or there to keep molecule safe side. But, can you talk about what you’re seeing sort of as we start the year? And how 2022 unfolds on that dynamic?

I’ll start it out and then take it from there. When we see increases on the domestic side, those are weather-related. At the end of the day, Tristan, the market for the incremental NGLs from the United States, which are substantial, is going to be at the dock. There’s just no doubt about it. And unless Justin feels otherwise, we’re going to say they’re largely pointed towards Asia. Am I missing something?

No. That’s it. Everything is going balance at the dock.

Our next question comes from the line of Jean Ann Salisbury with Bernstein.

This one is probably for Brent. Your NGL Pipeline segment was down $200 million in 2021 versus 2020. And you gave some helpful color in the release that Permian and Rockies pipes had pipeline or less. I guess, my question is what inning are we in, in terms of these NGL contract roll-offs? Obviously, a ton of Permian processing plants kind of came out in the last five or six years. So should we think of more contract rolls could still be to come?

So, I think this is the first full quarter that we’ve seen the Rocky Mountain contract roll-off in effect. On the Permian side, there’s some incentive rates that are in place. So, those are there to stay for a while. And then, if you look at across the MAPL system, the fact of the matter is in the fourth quarter, we didn’t really get much of a winter. So, from a propane demand perspective, quarter -- fourth quarter to fourth quarter, we saw some effects of that. We’re seeing a good January and a good start to the year, but there were some -- definitely some effects to propane lack of demand domestically.

Okay. That’s helpful. And then as my follow-up, this one might be for Tony. What is your latest projection of when Permian NGL production will warrant enterprise, either building more NGL takeaway or possibly switching Seminole [ph] back to NGLs?

It’s certainly...

Go ahead, Tony.

Yes. Well, I’ll tell you what, Teague, do you want to take it?

Sorry, Tony, I didn’t mean to cut you out.

Yes. I mean, if you look at our system, we have a lot of options, and you mentioned that we can repurpose certain assets, but call it, late 2024, we’ll be assessing whether we can do some brownfield expansions or evaluated greenfield project. Jean Ann, I want to make the assumption that it’s -- M2E2 is the one that gets repurposed. I mean, there’s some other better cost alternatives than potentially that one.

Our next question comes from the line of Michael Blum with Wells Fargo.

Just one follow-up on the last set of questions on the MAPL contract rolling off. Just wanted to clarify, was that renewed at a lower rate, or is it just not renewed in its operating more on a spot basis?

I believe so, and correct me on this. But, Michael, those were not renewed. Those contracts were to support the expansion from a number of years ago. And there’s those volumes are still flowing on this. They’re just kind of rolling at the tariff rate -- I’m sorry, there is deficiency revenue we are recognizing that we were no longer recognizing.

And second question, I was wondering if you can just give us a little bit of insight into your current conversations with producers. Are you seeing any change in their approach, any willingness to add more rigs, or is it pretty much status quo in terms of the real discipline you’re seeing certainly from the publics?

Go ahead, Tony.

Obviously, the publics remain very committed to discipline. That said, if you look at what Chevron has said in the last couple of days, you look at what Exxon said this morning, the Permian is their hot basin and they’re both going to increase activity there for 2022 and beyond. The other thing that’s very hard to get your arms around is there’s a lot of acreage, and I hate to just use that term generically that’s changing hands and what I would call is Tier 2 acreage. And that will be drilled. The private equities are picking it up and the privates are picking it up. So, that’s how we see it. We see rig counts, completions continuing to be added, and it’s very profitable. As Brent talked about, the gas takeaway situation has to be resolved. But we’ve been really, really outspoken about a large number. People thought it was very large, 1.8 million barrels for ‘21, ‘22 and ‘23, that’s crude oil production. And you can think about somewhere between 800,000 and 900,000 barrels of NGLs associated with that. And if you look at the crude oil number that the EIA published in December, we’re talking 600,000 barrels of increase in 2021. So, it’s not a stretch to say that that $1.8 million is probably a little on the low side, as is the liquids number. Did that answer your question, Michael?

Yes. Thank you very much.

Thank you. Our next question comes from the line of Spiro Dounis with Credit Suisse.

First question is just on spread opportunities heading into the year. I know in the past, you talked about anywhere between $500 million to $800 million in spread opportunities in any given year. So, curious on two fronts. One, do you have a sense of what that number ended up being in 2021? And as you look out into 2022, does it seem like this could be an environment to improve upon that number?

Last year? ‘21 is between $800 million and $1 billion. And I’d say, 2022 is probably going to be between $500 million and $800 million.

Back to the average. Got it. That makes sense. Thanks, Jim. Second one, just -- I know you’re going through the Navitas process now, so you probably can’t say much, but would just love to get your general thoughts on M&A in general. Just curious if there are other assets out there that check a lot of those same boxes as Navitas, and then just to get your overall appetite to do more tuck-in transactions that fit nicely into the EPD system.

I think I love Randy’s -- what Randy says. Price matters and it has to fit our value chain. So, I don’t think -- you never say never, but it’s got to meet some criteria. If you look at anything that Enterprise has ever done in terms of acquisitions, invariably, it brings something to the total value chain. And that’s a criteria we’re not going to breach.

And Spiro, this is Randy. I’d just add, Navitas is special because not only did it broaden our natural gas business into the Midland Basin where we didn’t have anything, it also broadened relationships with customers that we already had. And as Jim said, it’s complementary to our system. And again, the other thing is the cash accretion on the deal was superior to any assumption on buybacks. And also, no matter where we assume synergy capture, or even if we don’t capture $1 of synergies, this was superior doing a leverage parity buyback. So, very excited about the Navitas deal. And again, it’s a special transaction.

Our next question comes from the line of Keith Stanley with Wolfe Research.

I wanted to start on CapEx. So, the $1.5 billion spend for this year, that’s obviously consistent with the $1 billion to $1.5 billion you said that you thought you’d get to. But it’s up from $800 million, I guess, committed spend that you had talked to last time. So, can you talk to specific projects that were added? And then on the major capital project slide, it looks like it’s about $2.2 billion for ‘22 and beyond, was $2 billion previously. Just is that apples-to-apples, or how can I think about kind of comparing those two data points?

Yes. Hi, Keith. Good morning. Yes, we were -- what we were finding is when we were coming in and just talking about sanctioned projects only, it was tending to I guess it was understating really where we thought our CapEx would be. And I think Jim’s highlighted that we are working on a number of projects. And we came out this year and said, look, rather than coming in and trying to do surgery on what’s sanctioned and what’s not sanctioned that we’re working on, the $1.5 billion is just where we think we’re going to wind up for the year. And those are the sanctioned projects that we’ve been talking about that are included on that sheet that you saw in our supplemental slides that we posted this morning. And it was also some -- it also included these projects under development as well. The difference between the $2.2 billion and $2.1 billion, I think there are some small things that we’re doing from a natural gas gathering standpoint over the next two, three years that aggregated enough, it rounded to another $100 million. So, if you would have made that schedule.

Okay. Got it. That makes sense. A separate question just on Navitas. Do you have any -- can you give us a sense just of how much of the, I guess, revenue or DCF you’re thinking for 2023 is tied to commodity prices? Is it similar to your existing processing business in terms of fee floors, or is there more or less commodity exposure in this business versus your existing business?

Yes. And I’ll take a shot at this and Jim and Brent may want to come in and add some color. I think the way we look at it, just when we think about our equity NGL production, we’re probably adding probably an incremental 30,000 to 35,000 barrels a day of liquids exposure as a result of the Navitas deal.

The way we look at what we see over the next few years, commodity exposure isn’t necessarily a bad thing for us. I think we’ve -- Chris, we -- I think you said we had 18% commodity exposure last year? Was that your number? Where I saw that number -- but it’s not -- my point is, in this environment, a little more commodity exposure is not a bad thing.

Yes. And what Jim is highlighting is actually on page 9 of our supplemental slide deck. If you look over the last few years and really put that on the other side, when we come in and think about our fee-based earnings, they’ve ranged from 82% to 87% over the last three years. In 2021, it was 82%. So, spread related and commodity based was the 18%. And coming in and what we’ve said in the past, we really don’t mind a lower fee because that just means our commodity businesses are doing better. And again, just expanding on what Jim said, in this world where there -- and again, we think some of this is turning, but where there is an underinvestment in oil and gas globally, we just think from a structure standpoint, commodity prices will hold up well, and we just want more exposure to it.

Our next question comes from the line of Kyle May with Capital One Securities.

Just one question for me today. You mentioned the Haynesville as an area that could drive growth this year. Can you talk more about what you’re seeing in that area? And what kind of growth you expect this year?

Where is Natalie? Do you want to answer it? You can take the mask off to answer it.

We’re seeing growth. In fact, well, one of the things we’re doing right now is bringing [indiscernible] back up because Cotton Valley is being drilled. So, we’re bringing that processing plant back up. But as far as lean gas, our systems are starting to fill and our vision is that we’re going to have to probably go through some expansions as far as treating goes. So, all good things, all we’re seeing is increases in production.

Okay. DeWanda, this is Randy. We have time for one more question before we terminate the call.

All right. Our final question comes from the line of Yves Siegel with Siegel Asset.

Just a quick question. How do you think about the Northeast natural gas and NGLs, given problems with takeaway capacity?

Yves, this is Tony. We’ve always felt that that area was challenged. The rock, the resource is tremendous, both for dry gas and for NGL rich. The resource is incredible. But getting it out and getting it to market remains a challenge. And so, I think, you see the producers in the capital markets calibrating in that way. The question, just -- so I wondered three or four years ago, where is the incremental gas going to come from? Is it going to come from Appalachia or Haynesville? Well, it’s clear now that it’s going to come from the Haynesville. 50 rigs, 20 frac crews working. And as Natalie mentioned, Cotton Valley, we see the Haynesville on the marginal gas molecule as being the provider outside of oil-related gas.

Did that answer your question, sir?

Really well. Yes. Thank you. That’s it for me.

Okay. DeWanda, before you give the replay information, we’d like to thank everyone for joining us today for our call. And the Company is going to sign off now, and if you would go ahead and give the replay information to our listeners. Thank you. Goodbye.

Thank you. Ladies and gentlemen, a digitized replay of the discussion will be available beginning today, February 1, 2022, at 1:00 p.m. Eastern Standard Time and will end Tuesday, February 8, 2022 at 11:59 p.m. Eastern Standard Time. To access the digitized replay, please dial 855-859-2056 or 404-537-3406. Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect. Everyone, have a wonderful day.