Enterprise Products Partners L.P.

Ladies and gentlemen, thank you for standing by and welcome to the Q4 2021 Enterprise Product 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. To ask the question during this session, you will need to press star then 1 on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star then 0. 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, Dwanda. 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 Enterprises 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 the enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ, particularly 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 unit holders 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 working capital and opposite directions brought about by significant storage opportunities. We generated $6.6 billion of DCF in 21 compared to 6.4 in 2020. We had 1.7 times coverage We retained $2.6 billion of DCF in 2021 and head into 2022 with significant financial flexibility. We also increased our distribution again in 2021 to $1.81.5 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 and services and natural gas pipelines and services segments set gross operating margin records. We've also been focused on growing our petrochemicals and refined product 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, higher 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 volumes. As to CapEx, our growth capital spending in 2021 was $1.8 billion, with approximately $2.2 billion of major projects currently under construction. The largest projects put into service in 2021 include a C5 hydrotreater at Montbellevue, and we added pipeline capacity to move ethane from Montbellevue to Beaumont, another project to provide feedstocks to the growing Gulf Coast petrochemicals. In our natural gas services group, our Gillis lateral and Acadian-Hainesville expansion were put into service in December of 21. These projects moved growing volumes from Hainesville down to the LNG corridor in South Louisiana. In our petrochemical segment, we completed our ethylene export terminal and ethylene storage and pipelines. Our second PDH remains on budget and on schedule for in-service the first half of 2023. Our project team has done an outstanding job to ensure supply chain issues would not impact project schedule, and Graham and his team are happy to report that almost all major equipment is now on site, significantly de-risking any major equipment issues. We were also excited to announce the agreement to acquire Navitas Midstream. Navitas gives us an attractive entry point for our natural gas processing and NGL businesses in the Midland Basin. We anticipate closing this acquisition in the first quarter of 2022, subject to customary regulatory approvals. Navitas plans for the construction of another natural gas processing plant, which would also provide us additional organic growth. Last year, we have announced that we have joined forces with Magellan and ICE to promote a U.S. Gulf Coast futures crude oil contract. Early indications are that the contract is going to be well received. As ICE announced last week, that the contract traded well over 1 million barrels a day in just the first few days of trading. We're excited about what this contract means, not just for the U.S. producer, but for the global oil industry. We learned the hard way in April of 2020. that the perils that come with a futures contract that doesn't have adequate physical infrastructure. The ICE Midland WTI AGC futures contract has access to 14 ship docks in the Houston area, providing significant direct access for exports. In addition, Enterprise and Magellan's combined distribution systems offer access to approximately 150 million barrels of total crude oil storage capacity, and 4.5 million barrels of refining capacity. As we finish up 21 and move into 22, I'd also like to highlight the momentum from our evolutionary technology team. This team, led by Angie Murray, and from a commercial perspective, Kerry Weaver, is home to bright and creative people. We have a number of initiatives underway with major players in each segment of the energy value chain. In addition to working on lower carbon opportunities in areas like hydrogen, carbon sequestration, circular plastics, and renewable fuels, this team and our big data group constantly have a number of important projects underway using the billions of pieces of data that Enterprise has in order to improve the reliability of our systems and optimize these systems every day. For enterprise, in addition to supplying the developing world with the cleaner fuels it needs today, these teams are on a path to developing lower carbon projects that both complement our systems and are profitable. We would not have thrown the amount of horsepower into these initiatives if we didn't believe in their potential and profitability for our company. We had our best year ever for safety in 2021. There's no doubt in my mind that our employees truly care about one another and the communities where we operate. As we said in the press release, we are extremely proud and grateful for the teamwork and contribution of our 7,000 employees to enterprises financial operating and safety performance in 2021. Over the last two years, COVID-19 has whipsawed the global economy, including the U.S. energy sector. As always is the case, our people responded. In 2021, it was their efforts that enabled three of our four business segments to report record earnings that resulted in our company posting record gross operating margin, cash flow from operations, and free cash flow. Regardless of the situation, whether it's a freeze that shuts down the entire state, the world going into a dark hole caused by a global pandemic are the complete opposite in 2021 when demand and prices for our products and services soared. Our people proved to be creative and determined. We want to thank each and every one of them for yet another outstanding performance in 2021. Today Randy and I are largely going to focus on 21 results, and you'll probably have a lot of questions about 2022. But before we get to Randy, I'll finish with our thoughts on the changing sentiments around oil and gas. For some time now, the sentiment towards all traditional forms of energy, especially in political circles, has been very negative. Many said that the world should pull the plug on traditional energy as soon as possible and completely devote our capital and efforts toward renewable energy. Without a doubt, this was always naive. The world now realizes that an overnight transition to renewable sources of energy is not at all possible, as evidenced by the rapid development of various global crises, including high natural gas and LNG prices, high crude oil prices, and not seen since 2014 and runaway inflation not seen for about 40 years. Europe is starved for gas and is faced with heat or eat, while Russia, with its major oil and gas supplier, is amassing troops on the Ukraine border. Try as you may, it's hard to blame these crises on the pandemic. Over one-third of the world lives in energy poverty, mainly in developing countries. Europe's energy policies have now made energy poverty a reality in first world countries. As an oil analyst said, energy is the economy. We in the United States live in a country of plenty. We are a rich nation with a high quality of life, a creative culture, now also blessed with abundant energy. Maybe that has distorted our thinking about the situation in other countries or regions. People who don't want developing nations to have what we have are either in denial, hypocrites, or both. At Enterprise, we've been outspoken that it's going to take all of the above, not for a few years, but for decades to come. Look to comments made by a variety of sources, everyone from the IEA to the head of Saudi Aramco, members of the European Union, and even the U.S. Energy Secretary. Ultimately, they all message the same thing. Investment in oil and gas needs to ramp up sharply in order to revive the badly needed baseload traditional sources of energy that will be needed alongside low-carbon fuels and green energy to meet the world's growing demand. At Enterprise, we've never seen supplying energy to meet growing needs as two competing paths We're going to remain focused on supplying the world with the clean, low-cost, and reliable fuels it needs today, while also playing a role, an important part, in developing lower carbon alternatives. I think I've said enough, Randy. How about you?

All right. Thank you, Jim. Good morning. Starting with the fourth quarter income statement items, net income attributable to common unit holders for the fourth quarter. was $1 billion or 47 cents per unit on a fully diluted basis compared to $337 million or 15 cents per common unit on a fully diluted basis for the fourth quarter of last year. Net income was reduced by non-cash asset impairment charges of $120 million or 5 cents per unit in the fourth quarter of 2021. This compares to $800 million or 36 cents per common unit for asset impairment charges of fourth quarter 2020. So, before the impairment charges, EPU was 52 cents per unit for 2021 compared to 51 cents 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 of 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 46.5 cents per common unit with regard to the fourth quarter of 2021, which represents a 3.3% increase compared to the distribution that we declared for the fourth quarter of 2020. This distribution will be paid February 11th to all common unit holders of record as of the close of business January 31st. During the fourth quarter, we also repurchased approximately $125 million or 5.8 million common units. This brought our repurchases under our buyback program to $200 million or 9.2 million common units for 2021. As of year-end 2021, we have utilized 24% of our outstanding $2 billion buyback program, which was authorized in 2019. In addition to these buybacks, Enterprise's Distribution Reinvestment Plan and Employee Unit Purchase Plan purchased a combined $37 million of EPD common units in the open markets during the fourth quarter of 21 and $144 million for the full year. Our payout ratio, which we define as the sum of our cash distributions and buybacks as a percent of cash flow from operations before working capital changes, was 58% for 2021. The payout, the return of capital to investors, includes $4 billion of declared distributions and $200 million of common unit buybacks. Our 2021 payout ratio as a percent of free cash flow before cash provided by changes in working capital was 84%. As we previously discussed, our capital allocation strategy remains focused on an all-of-the-above approach, investing in quality midstream infrastructure with attractive returns, supporting and growing distributions, executing buybacks opportunistically, all while maintaining a strong balance sheet and financial flexibility. In terms of capital investments in the fourth quarter, total capital investments were $424 million, which included $325 million of growth capex and $99 million for sustaining capital expenditures. Total capital investments in 2021 were $2.2 billion, which included investments in growth capital projects of $1.8 billion and $430 million for sustaining capex. For 2022, we estimate growth capital investments to be approximately $1.5 billion. This estimate does not include capital investments associated with the partnership's proposed seaport oil terminal spot, which remains subject to governmental approval. We currently expect sustaining capital expenditures for 2020 to be approximately $350 million. We currently expect the acquisition of Navitas to close in the first quarter of 2022, and our estimate of $1.5 billion in growth CapEx in 2022 includes any Navitas-related CapEx in the year. Our total debt principal outstanding was $29.8 billion as of December 31, 2021. Assuming the first call date or final maturity date of our hybrids, the average life of our debt portfolio is 16 1⁄2 years and 20.7 years, respectively. Our effective average cost of debt is 4.4%. Our consolidated liquidity was approximately $7.3 billion at December 31, 2021, including availability under our bank credit facilities, and approximately $2.8 billion of unrestricted cash on hand. This amount of cash on hand, while elevated by historical standards, was reduced this morning as we retired $750 million of senior notes that matured, and we will retire an additional $650 million of senior notes on February 15th. Further, as we previously communicated, we expect to fund our acquisition of Navitas with a combination of cash on hand and borrowings under the partnership's existing commercial paper facility and bank credit facilities. Adjusted EBITDA for the fourth quarter of 2021 was $2.1 billion and $8.4 billion for the 12 months ended December 31, 2021. Our consolidated leverage ratio was 3.1 times after adjusting debt for the partial equity trade of hybrid securities by the rating agencies and also being reduced by the partnership's unrestricted cash on hand. With that, Randy, we can open it up for questions.

Okay. Thank you, Randy. DeWanda, we're ready for the questions from our listeners now.

Thank you. Ladies and gentlemen, as a reminder to ask the question, you will need to press star then 1 on your telephone. We ask that you limit yourself to one question and one follow-up, please. Again, that's star one to ask the question. To withdraw your question, you can press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from the line of Carlton Bean with Tudor Pickering. Your line is open.

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 raise, but hoping to understand if Navitas funding would steer you to lower payout.

Colton, this is Randy. You know, 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 come in and pay the debt maturities in February. So some of the cash would go towards the purchase price as well as borrowings on our buying credit facility.

Understood. Great. And then just on the operational front, a significant step up in frack 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 2022?

This is Zach. Some of that is a little bit of commodity exposure that the fracks have, so there's some blending margins. Some of that on the revenue side is 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.

Yeah, 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 bracket goes up.

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

Great. Appreciate the time.

Thank you. Our next question comes from the line of Chase Morveyhill with Bank of America. Your line is open.

Hey, good morning, everybody. So, Quick question. I guess there's growing concern when we think about the Permian and the 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, Permian EMPs driving the majority of the growth, which makes it a little bit more difficult to sanction you know, large greenfield projects, just given that everybody's going to want, you know, 10-year take-or-pay contracts. And the private EMPs, you know, 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. Do you want to take it, Brent, or do you want me to?

Yeah, this is Brent Seacrest. You know, 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. You know, most of the customers that we deal with, and you can see our customer lists, 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 haven't 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 problems. But there's certainly opportunities for us as enterprise in terms of the capacity that we have remained open to participate in these type of dislocations. We talked to our customers about a potential for a pipeline project, but, you know, 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's going to have to take more risk, whether it's the private E&P, whether it's the person going to build the pipe and, you know, do, you know, not 10 years or five years, which they're probably not going to do, or is it going to be the gas processor? Like, you know, 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 because the contracts may have to be, you know, signed by the gas processor versus kind of, You're the private EMP.

No, that's just something in the past. You know, 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 operational 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, in terms of how we go pitch projects, those are the ones that probably need to step up. Can we be complimentary to it? Possibly. But to me, ultimately, this is about producers stepping up to get this project done.

Okay, perfect. Quick follow-up on FA and exports. You know, 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, you know, where do you think you can take this? You know, do you take it to the 240,000 barrels a day, or are there actually some constraints, you know, with vessels or imports on the other side? you know, these docks 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, there are 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 and for us to be able to get closer to those sustainable rates of 200, maybe slightly above.

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

That's right. Great. Perfect. All right. Thanks, Justin. Thanks, Rhett.

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

Hey, good morning, guys. Appreciate your comments on Navitas and the opportunity in the Midland. 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 the development schedule as planned activity by existing customers or maybe recent commercial wins with new customers?

You know, we think that we know, 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 with their existing customers or what their plans are. 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 pull that's emerged that may create, you know, one-off opportunities here or there to keep molecules stateside. But can you talk about what you're seeing sort of as we start the year and how 2022 unfolds on that dynamic?

Brent, 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. 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 to balance at the dock.

Thank you. Our next question comes from the line of Janine Salisbury with Bernstein. Your line is open.

Hey, good morning. This one's 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 Rocky's Pipes had pipeline roll-offs. I guess my question is, what inning are we in in terms of these NGL contract roll-offs? Obviously, a ton of Permian processing plans kind of came on 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 winner. So from a propane demand perspective, quarter one, 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 definitely some effects of the 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 back to NGL?

It's certainly... Go ahead, Tony. Yeah. Well, I'll tell you what. Tug, do you want to take it? Sorry, Tony. I didn't mean to call you out.

Yeah, 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 ground-filled expansions or evaluate a greenfield project. Gina, I want to make the assumption that M2E2 is the one that gets repurposed. I mean, there's some other better cost alternatives than potentially that one.

Okay. Great. Thanks a lot. Thank you. Our next question comes from the line of Michael Bloom with Wells Fargo. Your line is open.

Thanks. Good morning, everyone. 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 and it's operating more on a spot basis?

I believe, Tug, correct me on this, but, Michael, those were not renewed. Those contracts were to support the expansion from a number of years ago. And those volumes are still flowing on this. They're just kind of rolling at the tariff rate. That's right. There was deficiency revenue we were recognizing that we're no longer recognizing.

Got it. Thank you for that. And second question, I'm 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, you know, pretty much status quo in terms of the real discipline you're seeing, certainly from the public? Thanks.

Obviously, the public's remained 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. 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, they're talking 600,000 barrels of increase in 2021. So it's not a stretch to say that that 1.8 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 Donuts with Credit Suisse. Your line is open.

Thanks, operator. Hey, team. First question is just on spread opportunities heading into the year. I know in the past you talked about anywhere between 500 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, Because it seemed like this could be an environment to improve upon that number.

Is that last year? 21 is between 800 and a billion. And I'd say in 2022, it's probably going to be between 500 and 800 million. Back to the average. Got it. That makes sense. Thanks, Jim.

The second one, I know you're going through the Navitas process now, so you probably can't say much, but we'd 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 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, you know, 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 if the cash accretion on the deal was superior to any assumption on buybacks, And also, no matter where we assume synergy capture, even if we don't capture a dollar of synergies, this was superior to doing a leverage parity buyback. So very excited about the Novitas deal. And, again, it's a special transaction. Great. Appreciate the call, guys. Thanks.

Thank you. Our next question comes from the line of Keith Stanley with Wolf Research. Your line is open.

Hi. Good morning. I wanted to start on CapEx. So the billion and a half spend for this year that's obviously consistent with the billion to a billion and a half you said 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 projects slide, it looks like it's about $2.2 billion for 22 and beyond. It was $2 billion previously. Is that apples to apples, or how can I think about kind of comparing those two data points?

Yeah. Hey, Keith. Good morning. Yeah, you know, 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 You know, 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 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 or three years that aggregated enough, it rounded up to another hundred million. So if you would have made that schedule.

Okay. Got it. Uh, that makes sense. Uh, separate, uh, question just on, on Navitas that 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?

Yeah, 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 per as a result of the Navitas deal.

You know, 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, I think you said we had 18% commodity exposure last year. Was that your number? I forget where I saw that number. But my point is, in this environment, a little more commodity exposure is not a bad thing.

Yeah, and what Jim's highlighting is actually on page 9 of our supplemental slide deck. If you look over the last few years and really look 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.

Got it. Thank you.

Thank you. Our next question comes from the line of Kyle May with Capital One Securities. Your line is open.

Hi. Good morning, everyone. 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's Natalie? You want to answer it? Try. You can take your mask off to answer it.

We're seeing growth. In fact, one of the things we're doing right now is bringing Pinola 2 back up because Cotton Valley is being drilled. So we're bringing that processing plant back up. 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. 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 Yee Siegel with Siegel Asset. Your line is open.

Well, thank you. Good morning, everybody. Just a quick question. How do you think about the Northeast, you know, natural gas and NGLs given, you know, problems with, you know, 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 and the capital markets calibrating in that way. And, you know, 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 Hainesville? Well, it's clear now that it's going to come from the Hainesville. You know, 50 rigs, 20 frack crews working. And as Natalie mentioned, Cotton Valley, we see the Hainesville 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. Thank you.

Okay. Dwanda, 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 p.m. Eastern Standard Time. And we'll end Tuesday, February 8, 2022. at 1159 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.