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Enterprise Products Partners LP
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Good day, and thank you for standing by. Welcome to the Enterprise Products Partners L.P. Second Quarter 2021 Earnings Conference Call. At this time all participants are in a listen-only mode. [Operator instructions]
I would now like to hand the conference over to your speaker today, Randy Burkhalter, Vice President of Investor Relations. Please go ahead.
Thank you, Shannon. Good morning, and welcome everyone to the Enterprise Products Partners’ conference call to discuss second quarter 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 for the call today.
During the 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 with that, I’ll turn the call over to Jim.
Thank you, Randy. Our businesses continued to perform extremely well during the second quarter. We reported over $2 billion of EBITDA for the second quarter. Our distributable cash flow was 1.6 times coverage.
Cash flow from operations for the second quarter was $2 billion was more than fully funded both our CapEx and our distributions. So as we sit halfway through the year, our distributable cash flow totaled $3.3 billion, providing $1.35 billion in retained cash. Second quarter results reflect the ongoing recovery in demand for hydrocarbons as the global economy continues to reopen some COVID lockdowns.
Our liquids pipelines transported 6.4 million barrels a day in the second quarter. Our natural gas pipelines transported 4.2 billion BTUs a day for the second quarter that equals 2019 volumes. Summing it all up in crude oil equivalent, we transported 10.2 million barrels a day. Our fractionation volumes remained strong at or near record of 1.2 million barrels a day. Our propylene production for the second quarter of 2021 was a record 113,000 barrels a day, and liquid volumes handled by our marine terminals for the second quarter were 1.6 million barrels a day, which continues to lag pre-pandemic first quarter 2020 performance of 2 million barrels a day, primarily due to the weakness in crude oil exports.
Really, this would be expected as strong prices, backward-dated markets and lower inventories at Cushing are signaling that volume needs to stay at home at least for now. In short, it shows that markets worked. This time last year, we were slipping deeper into the pandemic. It looked and felt like a black hole to some. But by this time last year, we had already returned to our headquarters office in what was virtually an empty Downtown Houston.
We set protocols. We started wearing masks before they were mandated. We put plexiglass around our cubicles. We insisted on keeping our distance. And we had hand sanitizers all over the building. But I really think it was a competitive advantage being back, because we worked as a team, we’ve moved products for our customers and our producers. We were buying and selling. We were arb [ph] in the system and collecting on steep contango in about every product we touched. We were determined in the middle of the pandemic to make money, not make excuses.
If fast forward to today and the environment and sentiment are completely different. In the second quarter, crude averaged $28 a barrel, and as we all know, traded severely negative on April 20, 2020. Almost overnight, rig counts dropped from 800 to less than 250, producers shut in significant amounts of production and the Texas Railroad Commission held an own land hearing on mandatory proration that was attended by 35,000 people worldwide. I gave testimony to this hearing, and I was very straightforward and probably wouldn’t have been as much so had I known we had 35,000 people listening.
Today, WTS sits at $72. Natural gas has more than doubled from $1.75 to around $4. Rig counts have returned to 500 and growing. Producers are self-financing their capital, paying down debt, and returning funds to their shareholders. Just to give you an idea for a couple of key products. We won’t go through all of them. This time last year, ethane was selling at $0.18 a gallon. Today, it’s $0.33. Propane moved from $0.35. Today, it’s what, $1.09, Brent. Eagle Ford Natural Gas prices up though, our gross processing spreads in the Permian, in particular, have gone from around $0.22 to $0.50 a gallon, responding to significantly increasing demand. Wholesale gasoline has moved from $0.75 to $2. It was as low as $0.50 in March of last year.
And refining utilization has moved from an anemic 70% at the low to over 90%. Crude and product inventories have gone from a hard to imagine 3.6 billion barrels, at least 600 million barrels of overstocked to below normal levels of 2.8 billion and continuing to fall. The economies are recovering and demand for virtually everything is increasing worldwide, pressuring supply chains.
Our cash flow – while our cash flows are markedly different largely because of the movement in all commodities from steep contango into backwardation. Our businesses and our employees prove time and time again that they will perform regardless of the environment, are today in what feels like something like hyper-growth. While a press release has a lot of details or bullets this way. During last year’s collapse, we leaned hard on our marketing teams. And we said at the time, our storage was worth its weight in gold as we took advantage of steep contango arb in the system, coupled with a significant cost cutting by our operations.
This year, with prices and volumes up considerably, our assets are who is leading the way with significant increases in volume for gathering and processing, pipeline transportation and exports, and what I’ll generate is described as fairly steady.
Moving to an update on capital. We expect our growth capital for 2021 to be $1.7 billion. We haven’t changed, I don’t think, Randy. For the rest of 2021, we continue to be on schedule to complete our Acadian gas system to Giles, the expansion of our ethylene and propylene pipeline systems, and the construction of our natural gasoline hydrotreater. Our growth CapEx in 2022 and 2023 projects currently sanctioned is $800 million and $400 million respectively. But we expect these to increase as some of the projects under developer – development are sanctioned. The long-dated capital is largely around our PDH 2.
We couldn’t be more pleased with the market fundamentals and momentum that we see in our petrochemicals business. The reopening of global economies has caused a surge in demand for propylene due to high demand from durables, which has caused the refinery grade to polymer-grade spread to widen from $0.15 a pound historically to $0.40 a pound. Our petrochemicals and refined products segment contributed five out of the total six financial and operational records. The strong performance of our petrochemicals business was led by our propylene segment, which offset lower results from our octane enhancement due to a planned turnaround.
Our Mont Belvieu propylene splitters achieved record throughput of 98% of nameplate, with strong margins, and our PDH plant operated at an average of 112% of nameplate following the planned maintenance in the first quarter.
Finally, we recently closed on a transaction acquiring the ethylene storage business from NOVA. This transaction, although it didn’t take a lot of cash is meaningful in that it is yet another milestone and the development of our petrochemical hubs, which is a key in furthering our petrochemical growth strategy. We feel very good about our strong position and our momentum in the midstream petrochemical space.
We’re pleased with how our assets and our people performed again last quarter. We have been outspoken about why we have been bullish on prices for well over a year, and have been preparing accordingly. The global inventory excess is that came with the global pandemic for the most part been exhausted. And it’s nice to see both supply and demand participating in what we believe will be a very strong extended recovery cycle. We expect continued upside in demand, both in the U.S. and globally, and appropriate production increases from the healthy U.S. E&P industry.
With that, Randy?
Thank you, Jim, and good morning, everyone. First, I’ll hit some of the income segment items. Net income attributable to common unitholders for the second quarter of 2021 was $1.1 billion or $0.50 per common unit on a fully diluted basis. This compares to $1 billion or $0.47 per common unit for the second quarter of 2020. Net income was reduced by non-cash impairment charges of $0.01 per fully diluted unit, both for the second quarter of 2020 and the second quarter of 2021.
Moving on to cash flows. Cash flows from operations increased to $2 billion for the second quarter, compared to $1.2 billion for the second quarter of 2020. The swing in cash provided by or used for working capital accounts between the two quarters explains $731 million or 90% of the increase. So again, changes in working capital accounts.
Free cash flow for the 12 months ended June 30, 2021. And again, we define that as cash flow from operations less investing activities, less distributions paid out to non-controlling interest in our joint venture projects, was $4.2 billion, compared to $2.7 billion for the comparable trailing 12 months ended June 30, 2020. We declared a distribution of $0.45 per common unit with respect to the second quarter of 2021. That will be paid on August 12. This distribution represents a 1.1% increase compared to the second quarter of 2020.
EPD’s distribution reinvestment plan and employee unit purchase plan purchased a combined $38 million or approximately $1.6 million EPD common units in the open market during the second quarter. Our payout ratio, which we define as – some of our cash distributions and buybacks as a percent of cash flow from operations over the trailing 12 months was 60% as of June 30, 2021.
Compared to the latest available data, which is 12 months ending March 31, 2021, for our non-peer midstream C-corps and MLPs, Enterprise had one of the highest payout percentages. In the near term, while we wait for better visibility on federal regulatory and tax policies as it pertains to the energy industry as we assess the potential opportunities and related capital requirements for energy evolution projects, we are continuing to make financial flexibility our priority at the margin. However, we do plan to opportunistically buyback common units in the second half of this year. The amount of the buyback would probably be comparable to the $200 million we purchased in 2020.
Turning to capitalization, our total debt principal outstanding was approximately $28.8 billion as of June 30. Assuming the first call date or the final maturity date for our hybrids, the average life of our debt portfolio was 16.5 years and 20.8 years, respectively. Our effective average cost of debt is 4.5%.
Adjusted EBITDA for the second quarter of 2021 was $2 billion and $8.4 billion for the 12 months ended. Our consolidated leverage was 3.24 times after adjusting debt for the partial equity content attributed to the hybrid debt securities, and further reduced by any unrestricted cash.
Our consolidated liquidity was approximately $5.4 billion at June 30, including availability under our existing credit facilities, and approximately $400 million of unrestricted cash on hand.
Finally, we expect to publish our annual sustainability report update, which is intended to supplement our 2019-2020 sustainability report next Monday on August 2. The report will be available on our website. We hope you have an opportunity to read it, and we look forward to publishing our next complete report in the summer of 2022.
With that, Randy, I think we’re ready for questions.
Okay. Thank you, Randy. Shannon, we’re ready to take questions from our participants.
Thank you. [Operator instructions] Our first question comes from Jeremy Tonet with JPMorgan. Your line is open.
Hi. Good morning.
Good morning.
Just wanted to follow-up on the energy evolution initiatives there as it relates to carbon capture, and just wondering, if you might be able to provide a little bit more detail, I guess, on what you see as possible there? Is this something kind of in the Ship Channel itself, a hub concept, do you see that as something that is possible at some point in the future? And if so, where do you think the carbon could be stored? Do you think it’s more of an onshore or offshore solution?
I guess it could be both. We’re looking at what we think are some low-hanging fruit. And then we’re looking along with a major chemical company and major oil company as to what we could do beyond that. And you can make a case to sequester it offshore, but you’ve got depleted reservoirs in the Permian, Tony, and so I mean we’re still in an infancy stage, but we’re beginning to see that there might be some low-hanging fruit that we can take advantage of.
Got it. That makes sense. I was just curious if poor – issues onshore kind of influenced the decision onshore versus offshore. But just also guess, I guess, what type of time line do you think that this could be really materialized over? It seems like we’re really in the infancy here. If the Texas Railroad Commission gets kind of primacy on the Class VI wells, that could really change things a bit here. And if we get more federal legislation within the 45Q to 85, that could really change things here. But curious as far as what you think the time line is for things coming together here?
Well, it’s not immediate for sure. Tony, you can add this?
Given the amount of regulation that’s in front of us, anything short of three years would surprise me. Angie, do you feel any different?
No. I think that’s about right on timing.
Got it. I’ll leave it there. Thank you.
Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.
Hi. Good morning. A couple of questions about the quarter. Your NGL pipeline gross margin was down kind of 8% to 10% from its usual run rate. The news release referenced lower grades and volumes on Dixie and Maple also some downtime, but it wasn’t clear to me how much was one-off and how much is kind of ongoing due to lower rates? Can you expand on that?
It’s a – Dixie was impact. We had a hydro test, so that would be, I’ll call that a one-off.
Okay. Because for the quarter, I guess, that segment was kind of 555 and it’s been a while since you’ve been in that low a couple of years. So just trying to figure out if that should be my new norm, plus some for the hydro test.
Yes. And, Jean Ann, this is Randy. I think there were also some we’ve got an integrated system. So to the extent we have NGL fracs down as well, I think we may have had some downtime over on Norco. But that could also impact the volumes moving across South Louisiana system, too. So there may be some ripple effects in that as well.
Yes. I think [indiscernible] probably, I believe, was down.
Okay. That’s helpful. Thank you. And then my other question is that the NGL prices year-to-date have obviously been very strong, but it hasn’t seemed to really hit your processing gross margin. Can you kind of just talk about why that is because gas price has also been strong or you hedged or something else?
I guess in terms of NGLs, Jean Ann, this is Brent. We have some key exposure, but it’s probably not as much as some of our peers. So last year, I don’t think in terms of when prices were very low, it wasn’t probably nearly as impactful to us as it was to others. In the same vein when prices have been higher, we probably don’t benefit as much as others. We do benefit, obviously. And I think the benefit that we have is more of a delayed effect in terms of what we see on volumes. And then ultimately, kind of what drives our business is it’s not just as high prices, it’s that gas to crude ratio where we see benefits in other parts of our business.
Yes. And, Jean Ann, one other impact may be out there as well is at the processing plant, we elect to extract ethane. And we may be working on variable economics as far as extracting that ethane, which would not be – the benefit would not be reflected at the processing plants. If anything, it would be a cost associated with that as the processing plants, and you get benefit on your downstream assets.
That actually makes sense. Cool. That’s all for me. Thanks a lot.
Thank you. Our next question comes from Shneur Gershuni with UBS. Your line is open.
Hi. Good morning, everyone. I appreciated the commentary in the prepared remarks today about returning capital to unitholders, including the $200 million of buybacks for this year. Randy, you spent a bit of time on today kind of highlighting the 60% payout ratio, kind of on a trailing 12-month basis for CFFO, which does include buybacks. Kind of wondering as you feel more comfortable with policy outlook and so forth, whether we could be thinking about 60% is kind of a signpost of where you’d ideally like to pay out to kind of shakeout with buybacks being a portion of it for not just 2021 but for like 2022 and beyond? Just kind of curious how you’re thinking about that?
Yes. Shneur, I have to go back in. I know we’ve got a slide in the deck – in our investor deck that shows over time what our percent payout has been as a percentage of cash flow from operations. And some of that’s impacted by changes of cash used or provided by working capital accounts. So it will move around depending on how much money we have tied up in working capital. But typically, I mean, if you go back and look over time, I want to say that I’m going off memory, that has probably ranged from 55% to 65%. So, I think that’s a range. I don’t think we’re going to come in and get precise dialed into the percentage that almost be like a tail wagging the dog. I think some of it is more of what’s going on in the business, what kind of cash flows are we seeing being thrown off. So, I don’t think we’re going to get as precise as 60% or 61% or 62%, but it would be more in a range.
Okay. That makes sense. Perfect. Appreciate that. And then sort of a follow-up to how you’re thinking about CapEx for 2022. I understand that you have $100 million of sanctioned projects. In addition to spot, are there any larger-scale projects that you’re evaluating, whether it’s on energy evolution or kind of on the base business that’s expensed today? But are there any projects that you’re evaluating or even in the permitting process that could move the number by more than $500 million for next year? Just kind of curious, where you are in terms of what you’re evaluating right now?
Yes. I’ll kick off with this, Shneur, and then see if Jim wants to add. We had mentioned really going back to, I think, our January call that we were working on a few projects that we – just for commercial sensitivity, we weren’t going to provide a lot of detail, and that’s still where we are today, that I can’t provide a lot of detail. But those – we’ll see – could it come in and add to 2022? Yes, it could. It could be in the $500 million incremental area. But I go back to what Jim said in the call back in these calls come around so quick in April, I guess, where he said, if you think longer term, something in the $1.5 billion to $2 billion run rate could be in the near term, what you could see our growth CapEx. I don’t know if we’d get to that number for next year. But I think that’s a good go above.
Okay. So, just to re-clarify, so 1.5% to 2% is kind of the range, but hard to kind of hit the top of the range next year?
I hate to underestimate our guess. But, yes, we – that’s how we feel.
We’d have to hurry, Jim.
Okay, that makes perfect sense. Really appreciate the color, and have a great day, guys.
Thank you.
Thank you.
Our next question comes from Tristan Richardson with Truist Securities. Your line is open.
Hey. Good morning, guys. Just remarking on the petchem business, strong results there, particularly on the propylene and PDH side. Clearly, the past few quarters have had some turnarounds and downtime. But just looking at this quarter, based on what you’re seeing from a spread perspective, is this a good general run rate for gross margin when the spread is available to you and facilities are online and highly utilized?
In the near term, I think we’re going to be hanging in here with this kind of results. Chris?
Yes, Jim. I agree. We should be in the same run rate with everything running and refinery utilization hanging in there?
Well, I was with – I’ve talked to a couple of CEOs from petrochemical companies. And what they both said to me is everyone and pull-out and they can’t catch up. So, we kind of like that business and probably see us do more things in it.
That’s great. And then I think you talked – historically, you guys have talked about in any given year there might be $500 million to $800 million of spread opportunities. And I think as of the most recent quarter, kind of talked about potentially 2021 being north of $600 million. Curious if that’s still north of $600 million is a comfortable figure or how we should think about, how that’s changed over the past quarter?
North of $600 million will be conservative.
Appreciate it. Thanks, Jim.
Thank you. [Operator instructions] Our next question comes from Keith Stanley with Wolfe Research. Your line is open.
Hi. Good morning. I first, just wanted to clarify the demand response items. So the total benefit, it looks like for Q2 was the $66 million in the release, and that’s across the fractionation and that seaway. And then also, I just want to confirm that’s incremental to the $250 million year gain you talked about last quarter. Right?
Yes, Keith. So, I think what we’re – probably in total, we’re looking at about $300 million in total. And then in the second quarter, yes, the benefit was probably around $70 million. And some of the reasons why you didn’t see that hit until the second quarter is frankly, we were waiting on clarity from the State of Texas as far as what the definitive settlement was going to be around ERCOT and around the LRS program.
Got it. Okay, one follow-up question on capital allocation. So just looking back, you raised the distribution slightly in Q4 last year. Should we expect similar timing for distribution growth announcements? And I guess, how are you thinking about distribution growth generally into next year versus buybacks as part of the capital return story?
Yes. Keith, I think the Board comes in. I mean, we take a look at the distribution every quarter. But here the last two or three years, we’ve done it where we’ve come in and really announced the increase in January for the next year. And I think we would probably stick to that. I don’t think that’s cast in stone. If you – as far as the whole thing on distributions versus buybacks, we’re an MLP. The most tax-efficient way to return capital and cash to your partners is through distributions. And that’s what we’ve done. I think we’ve got – this is the 23 year in a row that we’ve increased our cash distribution. And I – there’s not another midstream company out there that I know of that can say that. So distributions are really our first go-to.
As far as on the buyback side, I think as options professor talked one time, it depends. It depends on what your level of CapEx is, and I think we need to see not only the level of CapEx, we just need to get some better visibility on government policy because right now, there’s just a lot of question marks. I thought we would have known something by now, but it looks like that’s dragging out. But I think a lot of things go into the calculus of coming in and doing buybacks. But I think we’ve demonstrated our willingness to come in and do buybacks, but we’re just going to be deliberate in the way that we lag into it.
Thank you.
Thank you. Our next question comes from Christine Cho with Barclays. Your line is open.
Thank you. So maybe if I could start with the LPG market. There’s been market reports that you guys have been buying back cargos in recent weeks. Is this just marketing – your marketing subsidiary preparing for what could potentially be a short propane market in the coming months? It seems like the amount that you’ve been buying back is more than what your PDH facility could take, but any kind of color on what you guys are thinking there would be helpful?
Hey, Chris. I’ll start and give it to Brent. We bought it back because the fees were too cheap. We could make more money doing something else with the propane. Brent?
That’s it. I mean, at the end of the day, we look at every molecule and what the value of it is to Enterprise versus what we get across the dock, and what we achieved across the dock isn’t worth what we have, keeping it in the system.
Now could – is some of this potentially going into storage for like later, I mean, the curve is backward dated, so it just didn’t seem like you would be able to hedge things out.
Yes. I would not look at it as a storage play.
Okay. And then could you give an update around spot, just where the regulatory process is? What the next milestones are, especially if it’s to hit 2022 CapEx? And just given expectations for overall U.S. production growth isn’t what it used to be. Can you just go over your thoughts on why SPOT is necessary? And would you still need your crude export facilities along the gulf? Or would you look to potentially repurpose those assets for something else?
Yes. I think one of the things. We still believe SPOT is something – that we that is needed to serve. It’s kind of a magnet to pull things through your pipeline system. But we’ve got a strong anchor, and I think we’ve got some interest from others. We expect the final EIS to come out. I think it’s ready, by the Coast Guard. And the last time we heard from Marriott is to expect a permit in the fourth quarter. But yes, we feel like it’s a project. Now, we can build this project in phases and that’s what we intend to do.
And would you still keep your existing crude facilities along the Gulf?
I’m sorry, Christine, you did ask that. I think we need to – we’re looking at a need to expand our LPG capability out of the Ship Channel. So that’s what – is Bob Sanders in here? Let me talk to him – we’re looking at – we’ve got some expansion projects on our LPG facility on the ship channel.
We have a lot of long-term contracts that are on enterprise assets. And so if we have joint venture partners on the VLCC terminal, there’s still a need for what we have existing, and then it would be more of an optimization as it relates to the joint venture partners. But between petchem and NGLs, there’s ways to use those docks’ as crude oil.
Got it. Thank you.
Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Your line is open.
Hey, guys. Thanks for taking my question. A little bit of a theoretical one. How do you think – when you think about capital allocation versus CapEx, whether that capital allocation is deleveraging, buybacks or even just normal course distribution growth or special distribution payouts? How do you think about what your cost of capital is? And what is the return on new project has to hit to make it kind of a more valuable use of cash relative to some of the other alternatives?
Yes. Michael, I’m glad you asked that, because I was actually incomplete with my answer earlier. Because that’s one of the things that factors in there is when we come in and look at our CapEx and if you come in and you look at the buyback, when you – we look at what our return on capital is on the project, but we also look at what the downstream benefits are from a project that, again, we run a value chain system. So if we add a project, it has the ability to come in and add incremental volumes and incremental margin to other parts of our system. So that adds on to the project economics. And we look at that holistic return. And also it adds on – it increases EBITDA as well.
Compared to a buyback, I mean, I think, as I look this morning, I think we were yielding, I don’t know, 7%, 7.5%, our coverage is about 1.5 times. So, I think that rough math is probably between 11% and 12% cash yield, if you think about it from – if I go back to distributable cash flow because, again, that’s subtracting out maintenance CapEx. So that’s the bogey that we look at on the buyback side. And those are the two of the returns that we look at just from a return threshold.
Does that cover it all for you?
Yes. That helps a ton. And just trying to think about special distributions. Are there any reasons why special distributions would ever be off the table?
Michael, we’ve not really contemplated them in the past. I mean, a little bit, I’d turn that question on you. It seems like a lot of what I read in sell-side reports really dismisses the effectiveness of special distributions. If you’re – and I understand not being able to come in – the inability for the equity markets to capitalize a special distribution into the unit price, but frankly, our guys ran some correlation analysis the other day, and it’s crazy to me that when you come back in and you pick the period, three years, five years, 10 years, we actually have – our unit price has an inverse correlation to cash flow per unit. It has an inverse correlation to EBITDA. And really, the only correlation, the highest correlation that it has is to the price of the XLE, the S&P energy sector. So, I scratch my head anyway that the cash that we generate, our unit price didn’t correlated to the cash that we generate anyway. So, I’m – we’re in a little bit of a quandary. So, I don’t know if the special distribution would be good or bad, because I don’t know what our unit price correlates to anymore. But I go back to what I said earlier, the most efficient, tax-efficient way to get cash and return capital to limited partners is through distributions.
Understood. Cool. Thank you, guys. Much appreciated.
Thank you. Our next question comes from Gabe Moreen with Mizuho. Your line is open.
Hey. Good morning, everyone. Recently, there was – I guess one of your peers announced a JV transaction with a private equity-backed gathering system. Just wondering if something like that, is it interest potentially maybe circumvent, some of I think beyond antitrust issues you’ve raised in the past. Just curious what your thoughts on that?
Our thoughts on that transaction?
Yes. Specifically, if it might make sense in either the Permian or in over piped areas like the Eagle Ford, for example, and a way to consolidate the sector when private equity owns quite a bit of assets out there?
I guess we never say never. And, Randy, we’re kicking tires all the time. As to that, I don’t know that we would be interested in the joint venture with the private equity. I’d tell you, we’re spending a lot of time right now looking at our pipeline system and trying to determine what are the opportunities to repurpose. But, I mean, we look at everything, but I can’t see us doing a joint venture with a private equity. Can you, Brent? Do you…
I mean, to your comment never say never, but there’s a lot of opportunities that we look at, and we’ll see what comes of it.
Got it. And then maybe if I can just follow-up and ask specifically as it pertains to Randy’s comments about kind of waiting for definitive stuff out of D.C. on policy. What should we be looking for, is it really just tax rates? Are you looking kind of for the, I guess, the federal permitting, the infrastructure build, all of the above? I’m just specifically wondering kind of what – of those things, what’s most prominent, I guess, in your mind?
Yes, Gabe. I think it’s all of the above. And I mean some of it, even you could come in and say it’s even we’re – I think the energy industry is in a little bit of a conundrum.
Randy, you talk about the focus on supply and not on demand. You do good on that.
Yes. Because if you come in by last count, they are like 194 countries in the EU that have signed on to the Paris account. And part of that is coming in and trying to get to net-zero emissions by 2050. But none of those countries have enacted any policies addressed to oil and gas demand. And it seems like the policies that are being driven are more on supply. And more really, I think in the U.S., what we’ve seen thus far this year is really on domestic supply and but not anything on demand. And you come back in, I think that what we’ve heard out of you pick it IEA, EIA is the expectations, we’re going to be back to 100 million barrels a day of crude demand by the end of the year. And looking for that demand to grow, I think, again, no matter what EIA or IEA that you look at, looking for crude oil demand to grow for the rest of the decade, at least. And – but really, the only policies out there domestically are on supply constraints.
And so where that leads us is – and I think you’ve seen it to a degree. You’re going to end up with higher crude oil prices, higher motor gasoline prices across the board, which will be inflationary, but we’re at a little bit of a conundrum on energy policy in the country as well. The other thing that – well, because I mean in the most recent example is, I guess, with the – some of this has been going on since January. Domestically, we’ve come in and we were putting a freeze on permits on federal lands, but we’re asking OPEC Plus to come in and produce more oil so oil prices won’t go up, and so again, just a head-scratcher. And – but I think when you come in and you look, the world OPEC Plus countries, they have the capacity to produce more oil and they have the capacity to come in and respond to demand. Again, I think it’s going to be at a higher price. And you’ve seen recently whether it’s the Saudi Oil Minister or the Prime Minister of Norway, and I believe Norway is part of the climate agreement. They’ve both said that they’re going to drill and withdraw every last barrel of oil that they have in the ground.
So, we are – so gave up, I think there’s just a lot of unknowns out there. We’re early on in this energy evolution. We think we’ve got a role to play. In fact, when we look at midstream companies, on this whole energy evolution in handling carbon sequestration and hydrogen, we may be one of the early on that we can respond quicker than a lot of companies that are trying to do this from the get-go because we already have pipes everywhere, and we know geology. So again, we just need some more clarity, whether it’s tax policy, regulatory policy, energy policy.
And then frankly, I think the other thing that will be out there is just what we’re seeing, there’s so much changes going on at the FTC as well. But I mean, that’s more of a broad comment. It doesn’t matter if you’re in energy or in tech as far as what’s coming on into the – I mean, how the government in that regard too. So, I didn’t mean to get on my soapbox to you, but just again, painting on a little bit more clarity. And – but that’s not – but we will come in and act on opportunities as we see them come forward.
Got it. Well, thank you. Appreciate all those thoughts. Thank you.
Thank you. And I’m currently showing no further questions at this time.
Okay. Thank you, Shannon. With that, we will conclude the call today. And if you wouldn’t mind, Shannon, would you please give our participants the replay information. And thank you all for joining us today.
Thank you. This concludes today’s call. A replay will be available from 1:00 p.m. Eastern Time, July 28, 2021 to 12:59 p.m. Easter Time August 4, 2021. Please use the dial-in number 855-859-2056 or 404-537-3406 for International participants. Enter access code 986-9482. Thank you. And have a wonderful day.