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Operator: Good day, and thank you for standing by. Welcome to the Q4 2022 Enterprise Products Partners L.P. 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 . Please be advised that today’s conference is being recorded. It is now my pleasure to introduce Vice President of Investor Relations, Randy Burkhalter.

Randy Burkhalter: Thank you, Andrew. Good morning, everyone, and welcome to the Enterprise Products Partners Conference Call to discuss fourth quarter €˜22 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 for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities 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 with that, I’ll turn the call over to Jim Teague.

Jim Teague: Thank you, Randy. At our Analyst Meeting last year, we ended the meeting with all senior management, including Miranda, onto the front to take questions. Becca Followill at the time with US Capital Advisors asked me, what I’d like to see in our future. My answer was that I was tired of eights, I’d like to see a nine. Meaning that I was tired of our adjusted EBITDA starting with an eight, I’d like to see it start with a nine. Some folks took that as guidance, which it wasn’t, as at the time, I didn’t think it was possible. Once we returned to the office, I was visiting with Tug Hanley, kicking around the idea of creating a company wide goal of a nine. Doug said, let’s call it Project 9. So Tug was immediately appointed Chairman of the Project 9 initiative.

Tug was joined by 12 others to lead the effort, one of whom Rick Rainey, implemented an internal communications campaign designed to maintain our focus on Project 9 throughout the year with a poster themed around the Starship Enterprise, stating that we can only go where Enterprises never gone before. Tug Hanley, Yvette Longonje, and Daniel Boss introduced the initiative via a company wide webcast, and Starship Enterprise posters were sent to locations throughout the company. The prize was if we made $9 billion adjusted EBITDA, every employee up to and including senior directors would receive 3,000. And if we exceeded 9.3, they would receive 5,000. It was made clear that there would be no safety shortcuts. And very proud to report today that our core values for safety were reinforced in €˜22 with another year of our best year ever for safety performance with a 0.33 total recordable incident rate.

Also, we had zero lost time injuries in our trucking division where they logged something around 20 million miles for the year. We also emphasized that to achieve Project 9, we would not defer maintenance, pipeline integrity, mechanical integrity or anything we would ordinarily do. In other words, no smoke in mirrors. Our message was that no matter your job, you can always do it better. Through webcast, town halls and safety meetings, we encouraged our employees to come up with ideas that would help realize the success of Project 9. We asked them to share ideas and success stories. We received almost 200 success stories that resulted in something around $280 million toward Project 9 success. A couple of examples is we maximized MTBE production blending isobutylene and through the increasing MTBE production by a couple of thousand barrels a day.

Distribution, operations, commercial and our big data group work to find a way to adjust fractionation set points to increase throughput at our Mont Belvieu Complex. Project 9 gave every enterprise employee a common goal to boldly go where Enterprise has never gone before. For our folks that listen in on this call, when there is a number, albeit through your hard work, creativity, finding ways to do your job better and teamwork, we made $9.309 billion of adjusted EBITDA. So every employee up to and including Senior Director will be receiving $5,000. We had so much fun with this. And we decided we are going to have Project 9.3 for 2023. Again, don’t take it as guidance, because nothing is automatic, especially in this environment. As to numbers, we generated $7.8 billion of distributable cash flow in 2022 compared to $6.6 billion and €˜21 providing 1.9 times coverage.

We retained $3.6 billion in DCF, which compares to $2.6 billion in 2021. We set 13 financial records and 10 operating records in 2022. Operating results included record and NGL pipeline transportation, ethane exports, total NGL marine terminal volumes, fee based natural gas processing and natural gas pipeline transportation. In our petrochemical sector, we set operating records in propylene production, DIB processing and octane enhancement. In barrels of oil equivalent per day, Enterprise transported a record 11.2 million barrels a day of oil equivalent in 2022. Major growth for our capital in ’23 in addition to our second PDH, we have four gas processing plants under construction in the Permian and we’re constructing our 12 fractionator in Chambers County and we have expansions in both ethane and ethylene export facilities.

2022 was another volatile year with group trading as high as $120 and as low as $70. NYMEX natural gas traded between $9.50 to $3.50. Natural gas liquids also was no stranger to volatility. Ethane traded between $0.70 a gallon and $0.25 a gallon and propane traded between $1.60 and $0.60. For 2023, we are constructive on crude oil, but much less so on natural gas. Wide gas to crude spreads should lead to US petrochemicals having a very large cost advantage globally. On the supply side start with the fact that volumes from the strategic petroleum reserve provided a whopping 240 million barrels slug of supplies in the global markets most of it from the US. Those barrels are not going to be here in 2023. China seems to be open. IEA estimates Chinese demand will be up by 1 million barrels a day to 16 million by June.

This accounts for one half of expected global oil demand growth. The IEA also expects demand to hit a record of nearly 102 million barrels a day this year, 3/4 of the growth in non-OECD countries, which is just fine with us as we do have a nice real estate position on the water. One thing we believe there will be continued volatility in 2023, but our experience is volatility leads to opportunities. With that, I’ll turn it over to Randy.

Randy Fowler: All right. Thank you, Jim. Good morning, everyone. Starting off with the income statement. Fourth quarter net income attributable to common unitholders was $1.4 billion or $0.65 per common unit on a fully diluted basis. This compares to $1 billion or $0.47 per common unit for the fourth quarter of 2021. Adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital was $2.1 billion for the fourth quarter of 2022. This is a 16% increase compared to $1.8 billion generated for the fourth quarter of 2021. We declared a distribution of $0.49 per common unit for the fourth quarter of ’22, which is 5.4% higher than the distribution declared for the fourth quarter of the prior year.

The distribution will be paid February 14th to common unitholders of record as of close of business on January 31st. We will evaluate another increase in the distribution midyear in 2023. During the fourth quarter, we repurchased approximately 4.9 million common units at a cost of $120 million. For the entire year, we purchased a total of 10.2 million common units for $250 million. In addition, on a combined basis, our dividend reinvestment plan and employee unit purchase plan purchased 1.7 million and 6.4 million common units during the fourth quarter and for the full year of 2022, respectively. For 2022, we paid approximately $4 billion of distributions to Limited Partners. Together with our buybacks for 2022, Enterprise’s payout ratio of adjusted cash flow from operations was 54% and our payout ratio of adjusted free cash flow was 71% if you exclude the $3.2 billion investment in the acquisition of Navitas Midstream.

Now turning to capital investments. Total capital investments in the fourth quarter of 2022 were $763 million, which included $465 million for organic growth capital projects. $160 million for purchases of pipelines and related assets and $138 million of sustaining capital expenditures. During the quarter, we purchased approximately 580 miles of existing pipeline and related assets that enables us to cost effectively optimize and expand our NGL and petrochemical pipeline system on the upper Texas Gulf Coast. Total capital expenditures in 2022 were $5.2 billion, which included $3.4 billion for the acquisition of Navitas and the purchase of the 580 miles of pipelines, $1.4 billion for investment in organic growth capital expenditures and $372 million of sustaining CapEx. Last quarter, we had estimated $1.6 billion of organic growth capital investments in 2022.

However, approximately $200 million of this investment slipped into 2023. Our major growth capital projects under construction grew from $5.5 billion last quarter to $5.8 billion. The additional $300 million of projects under construction are really attributable to expansions in the scope of our new ethane — ethylene export facility and debottlenecking gathering systems in the Permian. As a result of the $200 million of CapEx slipping from 2022 into 2023 and the above additional opportunities in the Permian, we currently expect our 2023 growth capital expenditures to be approximately in the range of $2.3 billion to $2.5 billion and sustaining capital expenditures are expected to be approximately $400 million. Our total debt principal outstanding was $28.6 billion as of December 31, 2022.

During 2022, we reduced the principal amount of our debt outstanding by $1.3 billion. Assuming the final maturity date of our hybrids, the weighted average life of our debt portfolio is approximately 20 years. Our weighted average cost of debt is 4.5%. And at December 31st, approximately 96% of our debt was fixed rate. Our consolidated liquidity was approximately $4.1 billion at year end and this includes availability under our credit facilities and unrestricted cash on hand. In January, we issued $1.75 billion of senior notes comprised of $750 million of three year notes at a coupon of 5.05% and $1 billion of 10 year notes at a 5.35% coupon. We are appreciative of the strong continued support of our debt investors in this offering. We do not expect to return to the capital markets in 2023.

Adjusted EBITDA was $9.3 billion for 2022 and our consolidated leverage ratio was 2.9 times on a net basis after adjusting debt for the partial equity treatment of our hybrid debt and also reducing by the partnership’s unrestricted cash on hand. As Jim noted in the earnings release, we expect to achieve a major financial milestone in 2023, that is 25 consecutive years of distribution growth. As we looked at the financial attributes of the 65 companies that comprise the dividend aristocrats, these are the bluest of the blue chips. Some have over 60 consecutive years of dividend growth. The overwhelming majority had debt to EBITDA leverage ratios of less than 3.0 times and almost half were below 2 times. To support our financial goals to responsibly grow the partnership and provide our limited partners with a growing and resilient stream of cash distributions over the long term, we believe we have entered into a new era, which it is wise to have a stronger balance sheet than historical norms in the energy industry.

We are seeing our customers in the E&P, refining and petrochemical sectors do likewise. As a result, we are lowering our target leverage ratio from 3.5 times to 3.0 times, plus or minus a quarter of a turn. That is a range from 2.75 times to 3.25 times. And as we’ve noted earlier, our leverage for 2022 we ended at 2.9 times. So we’re in good shape with regard to this new target. We would be willing to temporarily take our leverage ratio above this target zone, if necessary, to complete an acquisition or an organic growth project that is strategic to the partnership. We believe this lower leverage target will be welcomed by our long term oriented investors who value distribution growth and stability. We also believe as more generalist investors consider income producing investments in infrastructure, the combination of Enterprise’ avoidance of double taxation and our history of distribution growth, coverage and lower leverage will make EPD attractive and that they may also start to consider EPD among the blue chips.

With that, Randy, I think we can open it up for questions.

Randy Burkhalter: Thank you, Randy. Andrew, we’re ready to take questions from our participants. I’d like to remind everyone to please limit your questions to one question and one follow-up. Thank you. Go ahead, Andrew.

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Operator: Our first question comes from the line of TJ Schultz with RBC Capital Markets.

TJ Schultz: First question, just on the 580 miles of pipeline and related assets that you purchased last quarter seems like a good price paid for that. If you could just provide more color on what you were able to purchase, how those assets will be integrated into your system? And if there’s any CapEx allocated to that in 2023 that may be driving part of the higher growth capital?

Chris D’Anna: I guess, first off, this is Chris D’Anna. The capital won’t increase or hasn’t increased as a result of that. Secondly, these pipelines are in a valuable corridor, which is going to allow us to optimize both our NGL business and our petchem business and provide other opportunities.

Zach Strait: This is Zach on the NGL side, I think if we look at the price we paid versus the optionality that Chris is describing, I think it made sense for us.

Jim Teague: I think you said capital, Chris, on one of your projects

Chris D’Anna: It also saves some — one of the other projects fairly small capital, it saved us a pretty significant amount of capital in that project.

TJ Schultz: I guess the follow-up is just a general question on capital allocation. You guys clearly continue to maintain plenty of flexibility, strong balance sheet with target debt leverage lower and you already sit there. So I’m just trying to see, do you anticipate any shift to more distribution growth? Is there any more intent on finding some of these acquisition opportunities like you did on the upper Gulf Coast, or how do share buybacks fall in there?

Randy Fowler: TJ, yes, I think between the Navitas deal and then the two deals that we did at the end of 2022, we are interested in asset acquisition opportunities that make sense that can come in and bolt on to our system and get good returns on capital that way. And that’s where the lower leverage gives us flexibility to come in and do these cash transactions to do that. I think over the last, call it the last 18 months, we’ve shown — we’ve sort of completed that pivot to go from an externally funded model to an internally funded model. And we had slowed distribution growth there for about three years or so. And over the last, call it 18 months, we’ve taken that distribution growth back up to about 5% area. So we have increased the pace of distributions.

And then the buybacks, we continue to do that opportunistically. So we feel like we’re in good shape to execute on opportunities that come to us in 2023, 2024. So we feel like we’re sort of checking the box of returning capital and all of the above and also maintaining lower leverage at the same time.

Operator: And our next question comes from the line of Colton Bean with TPH & Company.

Colton Bean: So just on Project 9.3, I appreciate the distinction that it’s an internal goal and not guidance, but two questions there. First, for Jim, has the team ever missed an internal goal? And then secondly, any high level comments as to how you achieve that, mark. It seems like commodity margins maybe a bit of a headwind, but then you have some sizable projects entering service throughout the year.

Jim Teague: I don’t think we’ve ever set a goal like this before. So thanks to Becca Followill for being the catalyst to it. We achieved it through everybody doing what they’re supposed to be doing, attention to detail, our employees work their butts of for this. And frankly, it created a lot of excitement. You had those posters up everywhere you’d go within Enterprise. And when a truck driver is asking you, how are we doing on Project 9, you know you’ve got some excitement. Project 9.3, we triggered like 9.3 in 2022 was quite an achievement. So we’d use that to start on the 2023.

Randy Fowler: And I don’t remember the last time we missed on internal goal.

Jim Teague: You just guaranteed guidance.

Colton Bean: And then maybe just a couple of questions on processing. So I think first, the Midland assets were down about 50 million versus Q3. So any indication as to whether we’re at or closer to the fee floors for Navitas now? And then second, keep hold pretty strong margins despite very high Rockies gas prices. So just curious if that was hedge related or any other comments there?

Jim Teague: Natalie, can you answer that?

Natalie Gayden: Yes, Colton, I’ll do my best. Midland down slightly in volume. There was — if you remember, there is a, I’ll call it, a Christmas winter event, where there’s some production loss in the field just a little bit. I think it’s a little bit longer to get or producing longer to get back up during that time. I wouldn’t count the Rockies out, to be quite honest, high gas prices are pretty good. So watch out for the Rockies. We’ve hit the C4 maybe once or twice, but Waha has been really volatile. So anyway, some processing margins probably down a little bit, but there’s some offsets, there’s some headwinds or some tailwinds that come from that.

Colton Bean: And so it sounds like on the Rockies, the higher price and drilling activity maybe offsetting the replacement cost there for the keepwhole contracts?

Natalie Gayden: Yes, it’s a fair assessment.

Operator: And our next question comes from the line of Harry Mateer with Barclays.

Harry Mateer: Randy, a follow-up question on the new leverage target. So historically, the sense I’ve gotten from you is that you preferred the flexibility of being in the BBB ratings category, but a leverage policy is a policy. So it begs the question given the rating agency upgrade targets are generally around 3 times up into low single As. Is that something you guys now would be open to and potentially welcome?

Randy Fowler: Harry, I’m going to send this one over to Chris.

Chris D’Anna: Harry, I appreciate the question. From our perspective, despite the lower leverage target, we’re still very comfortable at a high BBB rating. From our standpoint, what we don’t want to do is have the agencies upgrade us to at A minus and that removes the flexibility for us to be aggressive when it comes to external M&A opportunities, because what we don’t want to do is whipsaw the fixed income investor from a high — from A minus rating to a high BBB rating. So we want to maintain that consistency. So we’re very comfortable maintaining the BBB plus rating across the three agencies.

Randy Fowler: And Harry, I think one other thing the agencies look at on that A minus threshold is also looking at your cash distribution payout with regard to net income. And I think that’s just because we returned so much capital to our investors through distributions, I think that maybe a little bit harder threshold for us to overcome. So as Chris said, we’re pretty pleased with the BBB plus rating and ample flexibility.

Harry Mateer: And I guess the follow-up to that is just any sort of guardrails you can give us? I mean I know you mentioned you’d be comfortable taking leverage up higher for opportunities. But any sense you could like frame that out for us in terms of how high on a temporary basis over what sort of time period you’d look to bring leverage down?

Randy Fowler: Harry, I’ll be honest. I can’t envision a scenario where we would come in and take leverage up to a level that would threaten a BBB plus rating.

Chris D’Anna: And I think if you — Harry, again, this is Chris. If you look back a year ago to the Navitas acquisition, I think within that first quarter, that $3 billion acquisition bump leverage up a quarter turn and then it quickly came back down.

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

Jean Ann Salisbury: My first one is probably for Tony. Curious about your internal view of NGL pricing versus crude. How long do you anticipate it will take if we ever get there to return to the historical range of NGLs versus trade?

Jim Teague: What’s the historical range?

Jean Ann Salisbury: I guess for propane, I think historically, maybe 55% to 60%, something like that.

Tony Chovanec: Propane is going to price itself to go. So at the end of the day, the international markets are going to decide that. I’ll let Brent weigh in, but we think you’ll see more activity out of China. And so there’s there is support for that number as we head into ’23 as I see.

Brent Secrest: I think there’s going to be some lag, Jean Ann. I think China has got five PDH plants coming on this year. The plants they have existing currently are not running at full capacity. So as the China reopening occurs, it’s just going to take some time to work off some of the inventories over there. And once that economy gets back up and running and there’s enough dock capacity in the US then you can potentially see a rebound in LPGs. But it takes time, it’s going to take some time.

Jean Ann SalisburyAnalyst: But you think that we’re off the trough here, I suppose.

Brent Secrest: I mean, assuming reopening is going to be consistent, there’s no stops and starts, and I would like to think that the trajectory is up on a percentage of crude basis.

Jean Ann Salisbury: And then as a follow-up, Permian crude production estimates have come down over the last six months, I would say, pretty much across the board. The Midland to Houston price spread has kind of also come in. Is spot a more difficult pitch to customers in this environment?

Brent Secrest: I mean, I think ultimately, when you talk about spot and so like — I think Tony is going to lay out his forecast in our Investor Day. And I still think when it comes to volume, we have a bullish view of Permian volumes. And the question is, do you believe in the US producer and do you think that volumes are going to increase specifically out of the Permian Basin. And the next question is, do you believe that domestic demand is going to decline. And then ultimately, if you believe that crude production is coming online, it’s going to have to find its way to Houston because for the most part, its Corpus pipes are full. And then you got to think about the most environmentally friendly, the most efficient way and the most cost effective way to export those barrels to help them clear.

And in terms of the timing on spot when that could potentially come online, our conversations with customers, it’s still frankly a project that this market needs. And we’ve had good conversations. We’re in the process of a lot of meetings and a lot of trips. But I’d say, overall, it’s been positive.

Operator: And our next question comes from the line of Theresa Chen with Barclays.

Theresa Chen: I’d actually like to follow up on Jean Ann’s question related to spot. As you’re working through the process of getting an additional or other anchor shippers, how do you view the demand side of things if you have like a demand pull anchor shipper? Because I believe a lot of the large refining complexes in Asia that were previously under contemplation are taking incrementally more euros at this point. And as that flow reroutes, does that threaten the outlook for spot?

Brent Secrest: I think ultimately, I mean, we’ve talked about LPGs, we talk about LNG. This barrel is going to price to export. So from the routes that it takes that maybe different, I don’t — probably at one point in time, Theresa, I would have thought that we would have seen more global type customers. But I do think there’s going to be some producer push behind us. I do think we’re going to have potentially some traders involved with this project in terms of the advantages on freight to play in that game. But I think our view on global crude demand is probably more aligned with Exxon and BP. And we think that demand is going to be out there and it’s going to be out there for a fairly long time. And ultimately, we think a lot of crude oil has to come from this country to satisfy that demand.

Tony Chovanec: With our lighter barrels, it’s really a perfect fit for the integration that you see now in the large refineries in Asia that are integrated with petchem operations.

Brent Secrest: And if you look at the amount of VLCCs that are coming from the Gulf Coast, we’re north of 30 a month . There’s a lot to share between markets, between the Corpus market and also the Houston market, and that number is going to go up.

Theresa Chen: And then shifting gears a bit, can you just give us an update on your exposure to Waha basis given your open capacity on the Texas interstate business and your outlook on that through this year as well as the outlook for ethane economics recovery versus projection from the Permian?

Brent Secrest: The exposure hasn’t changed since our Investor Day. So I think we’re just probably shy of 400 million a day, Natalie. It has compressed over the last several months. You go back to Tony’s forecast, we’re still fairly bullish on volumes. There has been a new pipeline that came back online, that adds some compression. But ultimately, we think it’s going to be extremely volatile. We do think ethane is going to have to price to be recovered out of the Permian Basin. But if you look at that market, it’s not a whole lot different than the LNG market, the whole gas infrastructure in the US is very, very fragile. And when something happens out there, there’s a lot of volatility and I think we’re going to embrace that volatility as we go forward.

Operator: And our next question comes from the line of Neel Mitra with Bank of America.

Neel Mitra: I wanted to touch on the NGL fractionation fees and volumes on a year-over-year basis. It seems like the market is tighter just with Medford and frac coming online until mid-2023. Can you talk about the contributing factors, outages, what’s driving fees and where you see the market right now?

Zach Strait: So when Medford went down, no doubt, we saw an increase in spot fractionation fees. You since had some cooler weather, which helps with the fractionators run rates. You also had Philips come online with the fractionator. So we’ve seen that market kind of cool down. We also see a lot of capacity coming online this year, which I think the market needs. And then as far as our results, we obviously had some unplanned downtime. We had — the vast majority of the down from quarter-on-quarter was due actually to commodity prices and blending, and then some slightly lower frac fees on average, but it wasn’t nearly as significant as the blending. Going forward, really excited about Frac 12. I can say pretty confidently that fractionator will be full on day one.

Neel Mitra: And as a follow-up, looking at the kind of the propylene markets right now, that looks like the tough one with the PGP, RGP spreads. It looks like we’re at the trough in Q4. Can you kind of talk about how fast you see that recovering? And then in terms of PDH 2, when it comes online, how do you look at the volume outlook for that in terms of like a dispatch stack once you have that online versus the fractionators in PDH 1?

Chris D’Anna: I think as far as the spread, we saw throughout last year that tightening a bit. We’ve seen that widen out a little bit, but at first month of the year and really, it’s more of a supply issue than demand. And ultimately, for that spread to remain wide, we need propylene derivative demand to be strong. So China could play a part in that but we see that a little bit further out, maybe second half of the year. And a big part of that is during COVID propylene goes into durables and we saw that accelerate throughout COVID, the demand for those durables. So we think it’s probably second half of this year before we see that demand return.

Jim Teague: What about polyethylene?

Chris D’Anna: Polyethylene demand has strengthened quite a bit. And talking to customers from where we were last year at the end of December, exports grew quite a bit. One of our customers told us that December was the highest month of polyethylene exports that they’ve seen in five years. I guess just going back to your PDH 2 question. PDH 2 is 100% subscribed, so that’s going to be day one pull.

Operator: And our next question comes from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet: It’s been touched on a few different ways already, but I just want to bring it all together with regards to just economic conditions out there, potential and pending recession. And just wondering, specifically as it relates to your petchem business, how you see that faring in this environment? I think there’s some concern in the marketplace on that. So just wondering if you could walk us through the level of cash flow stability or other offsets that you see in that business line. Also, do you have any planned downtime for any of those facilities in ’23?

Chris D’Anna: I guess our petchem business is predominantly fee based. And what we saw last year was as spreads were wider than normal, we were able to capture — because of the way we structure our contracts, we were able to capture a part of that. Looking for ’23, on our octane business, we’re about 75% hedged at a pretty good spread. And then we expect the earnings for our propylene and PDH to be pretty consistent.

Jeremy Tonet: And maybe just one last one, if I could, as it relates to capital out there. Enterprise clearly has a fortress balance sheet relative to others in the space, and it seems like you can afford to be opportunistic if the right opportunity comes. How do you view the current, I guess, market out there as far as potentially acquiring assets, private or what have you? Is there anything — any other part of the portfolio that you would look to kind of round out through M&A?

Jim Teague: We — getting a position in the Midland Basin was important to us, and it’s proved to be pretty successful. I think Randy Fowler always says price matters and price does matter. I think we’re in a position right now that if there’s anything out there, it’s got to be pretty damn strategic for us to get interested.

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

Michael Blum: wanted to go back to natural gas for a moment. With the exception, maybe putting the Waha aside, which I think we all understand. Can you maybe just talk through the puts and takes on how this lower natural gas price environment will impact your business this year?

Brent Secrest: You said it, Michael, there is a lot of puts and takes. Lower price obviously affects our equity gas and that’s probably around $100 million a day. But if you look at our total gas burn and you equate our power consumption and you want to call that natural gas, at different price levels, we get imbalance. And the higher price, there’s probably some knock on benefits to us, but there’s a lot of pass throughs associated with this price. I mean the ultimate would be go sell the equity gas at the highest number, just wait and catch these load numbers, but we run a fairly balanced portfolio and it’s not — as Jim said, it’s fairly balanced. The last thing I’ll say, Michael, is that when you look at throughput in US petrochemical industry and you look at load gas and high crude, I mean, there’s a lot of benefits for our pipeline system.

Michael Blum: Just had one other question really about distribution growth in 2023 and beyond really. So you obviously raised the rate of growth in 2022. So I’m just wondering is that a new run rate, is there a reasonable range to think about going forward? And then kind of related to that, are you going to be going to like a one increase per year type of model?

Randy Fowler: Michael, I guess we did two increases in 2022. And we said we’ll come in and take another look at it at the middle of this year, really don’t want to come in and put out a marker of where expected distribution growth is going to be. We’ll come in and take a look at it mid year. Certainly, we pivoted off the slower rate that we saw there as we went from an internal funding — I mean, external funding model to an internal funding model. So you’ve seen that the growth bounced back up into the 5% area and we’ll come in and evaluate it as we do every quarter.

Operator: Your next question comes from the line of Brian Reynolds with UBS.

Brian Reynolds: We continue to hear discussions on the higher GORs in the Permian along with just continued discussion on parent child interactions. Curious if you could just discuss if you’re seeing higher GORs and higher parent child interactions that perhaps changing your view to the upside on associated gas production in the Permian going forward.

Tony Chovanec: The answer is we are continuing to see higher GORs. It’s not surprising. Look, putting it simplistically, oil declines faster than natural gas and shale basins. So we modeled it and we projected in our projections. Relative to parent child, I’ll tell you how we feel about it as a midstream company and watching all the rhetoric around it. We think parent child is a good thing, not a bad thing. And producers are learning more and more every day about it. And obviously, producers are getting larger in scale. We think when we read the different rags that parent child is a bad thing, it absolutely is a good thing. It’s how you get the most out of the reservoir. So frankly, we don’t sit up at night and — the producers and we see a lot of them and have a lot of talks with them in their conference room for things that we’re doing with them. I have to tell you, I don’t think any of the major producers are losing any sleep over it either. Brent, do you agree

Brent Secrest: I think that’s dead on.

Brian Reynolds: And maybe to touch briefly on just future growth projects. Post the quarterly results, it seems like free cash flow profile is keeping pace with the recent rise in growth CapEx. Just given Slide 6 in the presentation is largely unchanged, curious if you could provide a little color into whether we’re seeing new projects, i.e., processing plants are PDH 3 perhaps in the future, or is the rise in CapEx really just a function of maybe upsizing the existing projects, i.e., ethane exports or perhaps Shin Oak?

Jim Teague: I think our ethane and ethylene export expansions are pretty key. We’re going to see a lot more demand for those products going forward. Our ethylene export is chockablock full and our ethane exports are growing. So I like those. We’re building four processing plants in the Permian, two in the Delaware, two in Midland basin and probably all have Zach Strait knocking on the door, want to do the 14th fractionator, because we’re not going to do 13. But on a lot of our projects, there’s a knock on effect that we get out of those projects. So I can’t think beyond where we are.

Zach Strait: And probably add in some cost-efficient debottlenecking and the gathering

Jim Teague: Yes, we just picked up 580 miles of pipe for how much money?

Randy Fowler: $160 million

Jim Teague: $160 million in really key quarters. I mean, those kind of bolt-on deals will do all day long. As to PDH 3, I’ll throw Chris D’Ann out of my office if he walks in with PDH 3.

Randy Fowler: And as one astute analysts put it, it takes money to make money.

Operator: Our next question comes from the line of Neal Dingmann with Truist.

Neal Dingmann: My question is also on the petrochem and refined segment specifically. Could you give me an idea of your sales volume expectations for the remainder of the year for your Chambers County propylene facility, wondered any more downtime expected there? And then maybe secondly, just is that PDH 2 facility in Texas Western System still on pace for next quarter and later this year respectively?

Jim Teague: I think Texas Western is toward the end of the year, Graham?

Graham Bacon: Yes, that come on in stages.

Jim Teague: And PDH 2 is midyear?

Graham Bacon: Yes.

Chris D’Anna: And just in terms of sales, we expect those to be pretty stable. It’s really a function of refinery grade propylene supply coming out of the refineries and what their run rates are. And so looking at cracks today, it’s pretty profitable for them to run. So I would expect that to continue.

Operator: And our next question comes from the line of John Mackay with Goldman Sachs.

John Mackay: Maybe just going back to the Permian. We had — I guess there was a bit of a debate last quarter on just the pace of growth going forward. The Shin Oak kind of pushed to the right fell out of that, I guess. Just curious if you could update us there on again, when you think Shin Oak might be needed? I know you have the early €˜25 in the deck. So maybe just puts and takes on that timing and your general view on kind of NGL growth beyond this year out of the Permian.

Justin Kleiderer: This is Justin Kleiderer, I’ll speak to Shin Oak timing. I think we still feel good about that first half of €˜25. There’s probably room for it to be accelerated given its two years from now. And in the meantime, we’ve got various amounts of options to create incremental capacity if that first half ’25 doesn’t prove early enough and we can’t accelerate it. So we feel good at least for the next couple of years that we’ve got enough capacity. And then beyond that, we’ll continue to evaluate what projects are needed to make sure that we have enough capacity going forward.

Tony Chovanec: Relative to Permian production, just so everybody know the EIA reported yesterday growth in crude from year end €˜21 year to November of 741,000 barrels, that was down from what they reported in October. So I know that we hear different things and everybody looks at their own acreage and capture our own numbers. But these are — for lack of a better term, these are what the EIA calls actuals. We go back and we gauge our numbers to them. So we take a look back in our own models and directionally, these numbers are correct. And almost all of it, I’ll use that term , but comes out of the Permian Basin, has liquids associated with it. So no change in the trend for us relative to what the production profile out in the Permian Basin.

John Mackay: One quick one should be easy. Can you just remind us, are we done with the Eagle Ford contract roll offs? And maybe an update on what you’re thinking about the basin overall?

Jim Teague: We had a major producer tell us we’re in the second inning of a nine inning game in the Eagle Ford. I mean, the Permian just kind of dwarfs everything. But we had some — our contracts and the ones we did have some roll-off. We renegotiated a lot of those and ended up with life of lease dedications, which we kind of like. It seems like it’s becoming — it’s becoming kind of like the . It’s regional players and that’s where they are and that’s where they’re going to drill. But we haven’t forgotten the Eagle Ford by a long shot.

Randy Fowler: And our assets remain very full in the Eagle Ford, that would be a fair statement. Natalie?

Natalie Gayden: So processing, certainly, much fuller than the last two years, for sure.

Brent Secrest: Crude got capacity, but the contract roll-offs are over. I’d like to think everything that we had, incrementally, it’s going to be beneficial from a profitability standpoint.

John Mackay: That’s great. I appreciate the time.

Randy Burkhalter: Andrew, I think our time is up for today. And so I just wanted to thank all our participants for joining us for our call. And with that, we will be terminating or ending the call. And thank you, and have a good day. Bye.

Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for participating, and you may now disconnect.