EnLink Midstream, LLC

Greetings. Welcome to the fourth quarter 2022 NLINC Midstream Earnings Conference Call and Webcast. At this time, all participants are in listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero from your telephone keypad. Please note this conference is being recorded. At this time, I'll turn the conference over to Brian Bernkart, Director of Investor Relations. Mr. Bernkart, you may now begin.

Thank you, and good morning, everyone. Welcome to NLINC's fourth quarter of 2022 earnings call. Participating on the call today are Jesse Aranivas, Chief Executive Officer, and Ben Lam, Executive Vice President and Chief Financial Officer. Walter Pinto, Executive Vice President and Chief Operating Officer, is also in the room to answer any questions during the Q&A session. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. A replay of today's call will also be made available on our website at www.nlink.com. Today's discussion will include forward-looking statements, including expectations and predictions within the meaning of the federal securities laws. The forward-looking statements speak only as of the date of this call, and we undertake no obligation to update or revise. Actual results may differ materially from our projections, and a discussion of factors that could cause actual results to differ can be found in our press release, presentation, and SEC files. This call also includes discussions pertaining to certain non-GAAP financial measures. Definitions of these measures as well as reconciliation of comparable GAAP measures are available in our press release and the appendix of our presentation. We encourage you to review the cautionary statements and other disclosures made in our press release and our SEC filings, including those under the heading risk factors. We'll start today's call with a set of brief prepared remarks by Jesse and Ben, and then leave the remainder of the call open for question and answers. With that, I would now like to turn the call over to Jesse Arenivas.

Thank you, Brian, and good morning, everyone. Thank you for joining us today to discuss our fourth quarter and record full year 22 results. We'll also discuss our 2023 outlook, which looks like it will be another record year. In short, we remain focused on executing the same game plan that worked in 2022, driving sustainable value through investing in higher return projects, returning capital to investors, and executing on our first mover advantage in CCS. Looking back at 2022, we achieved a lot of in-link records. Last night, we reported fourth quarter adjusted EBITDA of $337 million and 2022 adjusted EBITDA of $1.285 billion. This marked both a record for annual adjusted EBITDA and our strongest ever year-over-year growth at 22%. We achieved these results despite December headwinds. Severe winter weather throughout Texas and Oklahoma, along with unscheduled downtime after an earthquake in the Permian, had a negative impact on adjusted EBITDA of approximately $11 million in the fourth quarter of 2022. The strong cash flow generation drove robust free cash flow after distributions of $312 million. This represents the third consecutive year generating at least $300 million in free cash flow after distributions. We use this robust cash flow generation in part to increase the returns to our investors. We recently announced an annualized increase to the distribution of 11% to 50 cents per unit. Additionally, we completed the Board-authorized $200 million unit repurchase program in 2022, and the Board has already authorized an additional $200 million program for 2023. Importantly, These returns to our investors were made while we simultaneously strengthened our balance sheet. In August, we refinanced most of our senior notes due 2024 and a portion of our senior notes due 2025, with an upsized offering of our senior notes due 2030. As a result, we have no meaningful near-term debt maturities. We exited the fourth quarter with leverage of 3.4 times. And subsequent to the end of the quarter, Fitch recognized our improving balance sheet when they upgraded us to investment grade with a BBB minus credit rating. We remain one notch below investment grade by Moody's and S&P with a positive outlook at S&P. Shifting to 2023, We look for this momentum to continue and expect another record year with adjusted EBITDA generation of $1.355 billion at the midpoint of our guidance we issued last night. In particular, we forecast our largest segment, the Permian, to continue to exhibit solid growth. During the fourth quarter, we also continued the execution of our bolt-on acquisition strategy with the acquisition of a small neighbor and GNP system in central Oklahoma. This is another example of our low risk consolidation strategy, which is designed to yield attractive returns in any market environment. We remain focused on maintaining a balanced capital allocation approach, and we continue to find very attractive opportunities to invest in high return projects, including the continuation of our capital efficient strategy of relocating valuable assets. Last night, we announced our third plant relocation to the Permian and the first to the Delaware, which represents a savings of approximately 50% over comparable new build cost. As we look to 2024 and beyond, our assets are well positioned for the structurally supportive natural gas market and the wave of LNG capacity coming online along the Gulf Coast. We generate approximately 90% of our gross margin from natural gas and NGLs, and we operate three dominant GNP systems in the Permian, Oklahoma, and North Texas. While natural gas price is currently lower in 2023 and may remain so for a period of time, long-term we see a significant call on North American natural gas and our systems are very well positioned to benefit. On the supply side, our Oklahoma and North Texas assets are the perfect gas-weighted complement to our Permian position. And on the demand side, we have a Louisiana footprint that can't be replicated, which will enable us to participate in supplying gas to the growing demand centers, including LNG terminals. In addition, we are taking advantage of those assets in the ground to create a differentiated future for NLINC by building a market-leading CCS business, complementing our diverse traditional midstream business. Last year, we executed on our first mover advantage with the first definitive transportation agreement for CO2 addressing current industrial emissions in Louisiana. We expect to sign additional definitive agreements beyond ExxonMobil in 2023 and beyond as we become the CO2 transporter of choice. Because of the extent of our assets in the ground, we can do this without cannibalizing our existing gas business. Next week, we plan to provide additional details around this unique opportunity and the evolving CCS business at our Investor Day in Dallas. With that, I will turn it over to Ben to provide an overview of our operations and our financial results.

Thanks, Jesse. And good morning, everyone. I'd like to start by thanking all of our team members out in the field. They not only operated in tough conditions to close out the year with winter weather, but more importantly, they did so in a safe manner. NLINK followed up a record safety performance in 2021 with another record in 2022. Our 2022 total recordable injury rate came in at 0.26. This is a testament to the actions we take to operate our assets with excellence while never compromising on safety. Let me walk through our assets, which drove record results for 2022, and then wrap up with some comments about our outlook for 2023. Let's start with our largest segment, the Permian, where segment profit for the fourth quarter of 2022 came in at $89 million. Segment profit in the quarter included approximately $11.7 million of operating expenses tied to the relocation of the phantom plant and $0.6 million of unrealized derivative gains. Excluding plant relocation OPEX and unrealized derivative activity, segment profit in the fourth quarter of 2022 decreased 15% sequentially, but increased over 27% from the prior year quarter. The fourth quarter results were adversely impacted by approximately $6 million as a result of unplanned plant downtime from an earthquake and severe winter weather. Average natural gas gas volumes for the quarter were approximately 1% lower compared to the third quarter of 2022, driven by the unplanned events. Producer activity across our footprint has remained robust from the fourth quarter of 2022 into early 2023. To meet our producer's plans on the Delaware side, we recently announced Project Tiger II. This will be our third plant relocation to the Permian, which will move a recently acquired plant from North Texas. The relocation will add 150 million cubic feet per day of processing capacity at roughly half the cost of a new build and is expected to be online in the second quarter of 2024. Turning now to Louisiana, we experienced favorable market conditions in the gas segment and normal seasonality in the NGL segment in the fourth quarter. Segment profit for the fourth quarter of 2022 came in at $97.8 million. Segment profit included unrealized derivative losses of $2.5 million. Excluding the impact of unrealized derivative activity, segment profit in the fourth quarter of 2022 increased approximately 8% sequentially and 9% from the prior year quarter. We continue to see robust demand for natural gas and NGLs in Louisiana. With the tightness in the NGL market, we agreed with our partners to restart Gulf Coast Fractionators, a 145,000 barrel per day NGL fractionation facility in Montbellevue, Texas. The facility is expected to restart in the first half of 2024. Moving up to Oklahoma, we delivered segment profit of $98.8 million for the fourth quarter of 2022. Segment profit in the quarter included unrealized derivative losses of approximately $5 million. Excluding plant relocation OPEX and unrealized derivative activity, segment profit in the fourth quarter of 2022 grew 8% sequentially, and nearly 13% from the prior year quarter. We achieved these results despite an impact of over $3 million from the severe winter weather in December. Average natural gas gathering volumes increased 5% sequentially and 3% compared to the prior year quarter. At the end of the fourth quarter, we closed an acquisition of a neighboring gathering and processing system. The acquisition is expected to generate approximately $19 million in EBITDA for 2023 and comes with attractive economics similar to those of our North Texas acquisition earlier in 2022. Like that acquisition, our investment case assumed no incremental customer drilling activity and is driven by operational and capital synergies. The acquired assets include processing capacity of 280 million cubic feet per day, which is significantly underutilized and will be available to support potential future volume growth on our systems. Wrapping up with North Texas, segment profit for the quarter was $84.3 million, including unrealized derivative gains of $8.7 million. Excluding unrealized derivative activity, segment profit in the fourth quarter of 2022 decreased 6% sequentially that grew 27% from the prior year quarter. The improvement over the prior year was driven in part by the acquisition that closed in the third quarter of 2022. Natural gas gathering volumes were 1% higher sequentially and 22% higher compared to the prior year quarter. These solid results drove another robust quarter with $337 million of adjusted EBITDA and $55 million of free cash flow after distributions. For the full year 2022, NLINC delivered adjusted EBITDA of $1.285 billion and free cash flow after distributions of $312 million. These results represent an impressive 22% growth in adjusted EBITDA over the prior year and the third consecutive year of over $300 million in free cash flow after distributions. We achieved these results despite the approximate $11 million impact of the December weather and earthquake events and despite incurring $3 million in severance costs related to an organizational realignment in the fourth quarter. Capital expenditures net to end link, plant relocation expenses, and investment contributions were $137 million. This included a $20 million contribution to our Matterhorn joint venture, bringing our total investment in Matterhorn to $66 million for 2022. On the balance sheet side, we continue to find ourselves in a very strong position with a leverage ratio of 3.4 times at the end of the year and ample liquidity. The credit rating agencies have taken note of the positive steps we have made to strengthen our balance sheet. Most recently, Fitch upgraded NLINK to investment grade with a triple B minus rating and a stable outlook. We remain one notch below investment grade at both S&P and Moody's with a positive outlook at S&P. Consistent with our capital allocation plans to increase returns to investors, we increased our common unit distribution by 11% in the fourth quarter of 2022, to 50 cents per unit annualized. Additionally, we remain active with our common unit repurchase program and completed the $200 million plan for 2022 with $53 million spent in the fourth quarter. We also repurchased $19 million of our preferred Series C units in the fourth quarter at an average price of 80 cents on the dollar. Now, let me turn to 2023 guidance that we announced yesterday. We are in a solid position to continue the momentum we ended the year with, and 2023 is forecast to be another year of record results. From an adjusted EBITDA standpoint, we're forecasting a range of $1.305 billion to $1.405 billion. This represents growth of approximately 5% at the midpoint of the range. It is driven by continued robust activity in the Permian, double-digit volume growth in Oklahoma, and continued stability in North Texas. Turning to commodity prices, our business remains approximately 90% fee-based. For our 2023 guidance range, we assumed average WTI and Henry Hub prices of $80 per barrel and $4 per MMBTU, respectively. While the pullback in natural gas prices may have been faster than we anticipated, we expected prices to moderate this year, and in turn, we took action in 2022 to hedge a large majority of our 2023 exposure to natural gas prices and WHAA basis at prices significantly above current levels, providing increased certainty for 2023 financial results. Accordingly, A change of plus or minus 50 cents per MMBTU impacts adjusted EBITDA by approximately $1 million. And a change of plus or minus $5 per barrel impacts adjusted EBITDA by approximately $11 million, in each case assuming no change in our forecast volumes. Looking at the segments, we are projecting another year of significant growth for our Permian business. At the midpoint, segment profit for 2023 is forecast to be $430 million. That includes $30 million of plant relocation expenses for Tiger II. Excluding plant relocation expenses, we forecast Permian segment profit at a midpoint of $460 million for growth of approximately 8.5%. Louisiana segment profit for 2023 is forecast to be $345 million at the midpoint of guidance. Oklahoma segment profit for 2023 is forecast to be $425 million at the midpoint. representing an increase of approximately 8% when excluding plant relocation expenses incurred in 2022. North Texas segment profit for 2023 is forecast to be $295 million at the midpoint. On the investment front, total capital expenditures plus operating expenses associated with project Tiger II net to end link and investment contributions are forecast to be between $485 million and $535 million. This spending includes the two new projects we announced last night with the Tiger II plant relocation accounting for $30 million net to end link and $25 million associated with our share of the restart at GCF. As a reminder, it also includes about $40 million related to our CCS project with ExxonMobil, which takes advantage of our existing assets in the ground. From a free cash flow perspective, we expect this modest increase in high return projects to offset the increase in adjusted EBITDA. As a result, we forecast free cash flow after distributions in the range of $210 million to $270 million. As mentioned earlier, our board authorized a new $200 million common unit repurchase program for 2023. In summary, the NLINK team delivered solid results in 2022, and we expect the momentum to continue in 2023. Despite the recent volatility, our assets are well positioned to grow, led by our largest segment today, the Permian.

With that, I'll turn it back to Jesse. Thank you, Ben. I'm proud of the NLINK team for their solid execution in 2022, which resulted in a number of records for NLINK. As our guidance shows, we're well positioned to build upon our record year, and I'm excited about what the future holds. With that, you may now open the call for questions.

Thank you. At this time, we'll be conducting a question and answer session. If you'd like to ask a question, please press star 1 on your telephone keypad, and a confirmation tone will indicate your line is in the question queue. You may press star 2 if you'd like to remove your question from the queue. For participants that are using speaker equipment, It may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for questions. Thank you. And once again, that's star one. Thank you. Our first question is from the line of Colton Bean with Tudor Pickering Hall. Pleased to see you with your questions.

Good morning. Just a couple of questions on the volume outlook for 2023 here. So I think looking at Oklahoma, guide looks consistent with the double-digit growth. And I think Devin mentioned yesterday that they're targeting high signal digits for the Anadarkos. Just be curious, you know, are you seeing better growth from other counterparties, or is that just the difference in terms of where specifically the drilling activity is taking place?

Hey, good morning, Colton. This has been a little bit of both. You're right. We do expect to see double-digit gathered volume growth in Oklahoma, and we did see Devin's comment last night, and we think that that will help demonstrate to our investors our level of confidence, that they share confidence in volume growth. But Devin's not our only customer. We've had about nine rigs running in Oklahoma year-to-date, of which four have been Devon, and the other five have been operated by four different counterparties. So we expect to see them contribute a bit to volume growth as well.

Great. And I guess for the other five, just to follow up there, any rough breakout between public and private activity?

It's mostly private activity, the others. You know, we don't necessarily expect to see nine rigs operating on dedicated acreage throughout the year. You know, we don't need that. The bulk of the volume growth does come from the Devin Dow JV, but the private operators do contribute, you know, a couple of percentage points.

Better said. And then just for North Texas in 2023, you know, it looks like it's a little bit lighter than the second half of 2022 once you have the the acquisition place, does that guidance assume that the two rigs running today remain for the entirety of the year?

Yeah, so let's do a little take apart the North Texas number a little bit. You're seeing a few things there. One is that while we've seen volume stability on the legacy in-link assets, The acquired assets are still on a slight decline, and so you're seeing a little bit of decline from the second half actuals on the acquired assets. There's also a little bit of price impact in North Texas. It's very modest compared to some of the other areas, but there is a modest price impact. And then, no, we don't necessarily expect to see the two rigs that are working on dedicated acreage stay in place. I mean, just being realistic, given where gas prices are today, if we see a reduction in activity, we would expect to see that first in North Texas. We haven't seen it yet, but just being realistic with how we're guiding the market, we feel like we should allow some room for that to happen.

It sounds like the North Texas number does assume a little bit lighter activity than currently.

That's correct.

Great.

Thank you. Our next question is coming from the line of Christopher Jeffrey with Mizuho. Please receive your questions.

Hi, everyone. Thanks for taking my question. Just maybe chip-shotting off of what Colton said, is there any impact on the double-digit growth rate coming from that Oklahoma acquisition, kind of how you're thinking about it?

Yeah, the double-digit growth rate really is on our legacy in-link assets and excludes the impact of the acquisition. Of course, as we start reporting the impact of the acquisition, you'll see a little bit of contribution from it. For reference, the acquired assets in Oklahoma have a volume today of about 80,000 MCF a day, 80 million a day. Got it. Thanks.

And then maybe just looking at the maintenance capex seems to be taking a bit of a leap in 23, wondering what is contributing to that. Is it inflation, bigger footprint, or some catch-up spending? And kind of should we expect a similar directional outlook for O&M and G&A spending?

Yeah, I'd like to take that in the order that you asked it. In terms of the maintenance capex for this year, You're seeing a little bit of impact from bigger footprints. It's, you know, more assets, you know, given we've had a couple of acquisitions and we've, you know, we've brought a couple of plants online. But the main thing is the timing of the maintenance cycle. Most of the increase over last year reflects more compressor overhauls, some of which are on turbine compressors and those cost, you know, a couple million dollars a piece. It's not necessarily indicative of a run rate because that does come in a cycle and in 2023 we happen to have more of those compressors coming to the point of needing major maintenance than we had last year and frankly more than we expect to have next year. That does flex a little bit with activity. If you don't accrue the hours on the machines, you don't need to do the overhauls and so it'll move around a little bit as volumes move around. Doesn't really have any read-through into O&M or into G&A. We think the G&A number for this year will be roughly flat to last year. And O&M, like everyone else, we're seeing a little bit of cost pressure, mainly around consumables. That is more than offset by the inflation escalators that we have in the commercial contracts, such that inflation on a net basis isn't really much of an issue for us.

Got it. Thank you.

The next question is from the line of Michael Cusimano with Pickering Energy Partners. Please proceed with your questions.

Hi. Good morning, everyone.

Morning. Morning.

I was hoping to talk about GCF a little bit. Can you give us a little more detail, you know, really what went into the discussions to bring it back online, and if you can talk about the, you know, any contractual arrangements you have there, or are you bringing on, you know, just spot frack capacity?

Yeah. So, first of all, just as a reminder, GCF is in Mont Bellevue. It has a capacity of 145,000 barrels per day, and we own 38.75% of it. and our partners are Targa and Phillips 66. The discussion with, and we idled it a couple of years ago because it needed some major maintenance and at the time the frac market was pretty soft and none of the three partners really needed the asset in our frac portfolios. What's changed is the frac market has tightened up as volume has grown. and all three partners now see a role for the FRAC in their portfolios, and so the discussions around bringing it up were merely to confirm that each of us had a need for it, and for the operator to develop a restart budget. Our share of that restart budget is about $25 million that we'll contribute this year, and we'll see the FRAC come up in the first half of 2024. In terms of the volume that will go into that FRAC, We've been handling a portion of the barrels we control through offloads to third parties in Mont Bellevue. And most of our capacity will be accounted for by allowing those offload arrangements for third parties to expire and redirecting those barrels to GCF, the asset that we own.

Got it. Okay. That's helpful. And then looking at the Permian volumes, For fourth quarter, can you give us an idea what warm rate levels might look like today? Or maybe if you could provide like the throughput impact, just trying to get a normalized level for 4Q, X weather and the earthquake impact.

Yeah. So the most important thing to know there is, but for the fact that we had the weather and we had the earthquake, we would have seen sequential growth in the Permians. It's a little bit hard to say precisely how much because the two events were so significant for the last two or three weeks of December and, frankly, even carrying over a little bit into January. You'll see, you know, I think you'll see that when we report 1Q in May. But suffice to say that we would have seen some sequential volume growth in the Permian absent those events. It's just hard to say exactly how much.

Got it. All right. Well, that's all for me. I appreciate the help.

The next question is coming from the line of Spiro Donas with Citi. Please proceed with your questions.

Thanks, Operator. Morning, team. Jesse, first question for you just on CCS. I know you've got the investor day coming up next week, so I don't expect you to get too much ahead of that. But just curious, since that Exxon deal, how commercial momentum has been there? I'm curious what you're seeing in terms of any gating items to signing similar deals going forward. Any color there would be appreciated.

Yeah, good morning, Spiro, and thanks for the question. Look, I think the momentum is continuing to strengthen. Post-IRA, you've got both the emitters and numerous sequestration players in the market. I think those discussions are ongoing with multiple parties. We do expect to give you an update next week. So hopefully we see you there next week. But the momentum's there. We do expect 2023 is going to be a very active year on the CCS front in Louisiana.

Great. Appreciate the color there. I'll definitely stay tuned for next week. And then just on free cash flow after the distribution and the buyback and thinking about capital allocation, you guys highlighted two other buckets there, of course, repurchasing the preferred units and then potentially spending on some more high-return projects. And so as you prioritize those, would you sort of force rank one above the other? Just any help you can provide in terms of thinking about where those dollars get spent and really thinking more about, you know, is there a backlog of potential projects that you see, or is this really truly more opportunistic as things come to market?

Yeah, Spiro, let me start, and I'll let Ben weigh in more on the philosophical approach. But when you look at the incremental capital spent this year over 2022, you know, these are high return, which will always prioritize value-added high return projects. And these are very strategic projects. Of the incremental, 115 of that are very discreet, you know, growth in the Delaware Basin and relocation of a plant. And then our downstream focus growth is, you know, GCF is obviously one component of that. Venture Global is another expansion we're doing there. And then, you know, $40 million is what we were spending in 2023 on the CCS business. So as you can see, these are high return multi-year additions to our portfolio. So we'll always prioritize high return projects. With respect to how we allocate the rest of the capital, I'll let Ben weigh in.

Yeah, just to build on what Jesse said, we'd always love to fund incremental high-return organic projects. That would be our first priority if we find additional opportunities this year. Absent that, the additional $40 million in free cash flow after distributions after the $200 million common unit repurchases would be available to do additional common unit repurchases or some other means of capital structure reduction. We did in the past quarter redeem $19 million of our preferred C units at 80 cents, and we like the risk reward on that. But that's going to be opportunistic. It's going to happen when we have a good risk return and a willing seller and not, you know, I would not describe it as a priority for us.

Understood. Appreciate the color. Thanks for the time, guys.

Our next questions come from the line of Jeremy Tonay with JP Morgan. Please proceed with your questions.

Hey, guys. This is for Jeremy. Just to mention the weather impacts in 4Q. I was just wondering if you guys could provide any incremental details as to think about the magnitude of impacts in 1Q.

Yeah, it's relatively modest in one queue. It continued between the weather and the earthquake. It continued for probably the first 10 days or so of January. The important thing to know is we've accounted for that in the guidance that we gave you last night, so it's not creating a risk to the guidance at all.

Gotcha. That's helpful there. And then switching topics a bit, talked about notable hedging. into 2023. I was wondering if you could run us through the 2023 EBITDA breakdown between fee-based hedge commodity and percent commodity price exposure.

Yeah, our business is about 90% fee-based, and that has been the case for a couple of years and really hasn't changed. What we did proactively for 2023 was is to hedge the majority of in-links exposure to natural gas prices, both NYMEX and Waha basis. And we did that at prices in 2022 that are significantly higher than what we're seeing today in the market. And we did that because we're not surprised at where the gas market is today. We got here a little faster than we expected. because of how warm the winter has been, but we're not at all surprised to see the gas trip for the balance of the year in the $3 range. And we took the opportunity to get ahead of that a bit. So the result of that is a change in gas prices, all else equal, has very little impact on InLink for 2023. A 50 cent change in gas only impacts our margins by about a million dollars. We've also hedged a significant portion of our MGL and crude exposure, not as much as gas, and a $5 change in WTI prices equates to about an $11 million change in our gross margin.

Got it. That's helpful. If I could just squeeze one quick one in. Is the 2023 CapEx run rate something or CapEx some run rate we can think of going forward, or how should we think about that?

Yeah, I think it's a little too early to tell. Like I said, we outlined, you know, kind of the bigger discrete items for you that are one time in nature. You know, we'll continue to evaluate as Ben said, you know, we'll look at the high return projects. You know, we are seeing a lot more opportunity in Louisiana on the downstream side. So, you know, we'll just have to update you as we go here.

And the only thing I'd add to that is I think over time, you'll see us devote more and more of the capital budget to CCS opportunities.

Got it. Thanks for the call, guys. Leave it there.

Thank you. As a reminder to ask a question today, please press star 1 from your telephone keypad. The next question is from the line of Samuel Sebald with Seaport Global. Please proceed with your questions.

Yes, hi, good morning, everybody, and congrats on a good 23 guidance. I wanted to start off on the balance sheet side of things. So good to see, you know, rating upgrade at Fitch. I was kind of curious, you know, how do you see discussion with other agencies? And specifically, you know, I think in some of the agencies, kind of in some of the instances I've talked about, you know, perhaps as part of the capital structure, I was wondering if you could talk about that and your longer-term plans on the PREFS.

Happy to do that and appreciate your highlighting the Fitch upgrade to investment grade in BBB-. We are one notch below at both Moody's and S&P with positive outlook at S&P. From our perspective, we've done everything that we need to do to be rated investment grade, ending the year at 3.4 times levered with a lot of liquidity and I think a very positive business outlook that we've outlined for everyone last night and then again on the call today. So we think we've done our part. We obviously can't control the timing of any decisions by the other ratings agencies, but we're optimistic that we'll see more than just the upgrade from Fitch over the course of the year. In terms of the plans on the preferreds, I'd reiterate something I said a little earlier. We've been opportunistic in chipping away at the preferreds when the opportunity has arisen and the price on offer was one that we thought presented a favorable risk-reward. So we chipped away at the Preferred Series B last year, and then we chipped away a little bit at the Preferred Series C in the fourth quarter of 22 as well, again, at prices that we thought made sense. we're gonna be opportunistic on those. We don't consider it to be a priority to eliminate those preferreds today.

Okay, got it. And then one question with regard to your contract structures. I think some of your other midstream players, especially in the Permian, have talked about, you know, contracts with POP slash POL with fee-based floors. So when you mentioned the 90% fee-based contracts, do you include such-like contracts in that fee-based? And then kind of a follow-up on that, how does, if you have those kind of contracts, how does the fee-based floors kind of compare to where the current commodity prices are?

Yeah, our contracts generally are either fee-based, fixed fee, or they're POP contracts that have both a POP component and a fee component. So not necessarily a floor, but a fixed number of cents per MMBTU or MCF plus a POP component. Does that help? So there's not really a comparison to current commodity price. There's just both a fee element and a POP element. and we include the fee element of the contract when we talk about the percentage of the business that's fee-based.

Understood. Thanks for that clarity.

Thank you. At this time, we've reached the end of the question-and-answer session, and I'll turn the call over to Jesse Arenavas for closing remarks.

Thank you, Rob, for facilitating the call this morning, and thank everyone for being on the call today and for your continued support. As always, we appreciate your continued interest in investment in Inly We look forward to seeing most of you in Dallas next week when we host our first Investor Day on February 23rd. In the meantime, we wish you well, stay healthy, and have a great day.

This will conclude today's conference. Thank you for your participation. You may now disconnect your lines at this time. Have a wonderful day.