Summit Midstream Partners LP (SMLP) 2021 Q4 法說會逐字稿

Good morning, and welcome to the Fourth Quarter 2021 Summit Midstream Partners LP Earnings Conference Call. My name is Brandon, and I'll be your operator for today. (Operator Instructions)

I will now turn the call over to Ross Wong. And Ross, you may begin.

Thanks, operator, and good morning, everyone. If you don't already have a copy of our earnings release, please visit our website at www.summitmidstream.com, where you'll find on the homepage, Events and Presentations section or Quarterly Results section. With me today to discuss our fourth quarter of 2021 financial and operating results is Heath Deneke, our President, Chief Executive Officer and Chairman; Bill Mault, our Chief Financial Officer, along with other members of our senior management team.

Before we start, I'd like to remind you that our discussion today may contain forward-looking statements. These statements may include, but are not limited to, our estimates of future volumes, operating expenses and capital expenditures. It may also include statements concerning anticipated cash flow, liquidity, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can provide no assurance that such expectations will prove to be correct. Please see our 2020 Annual Report on Form 10-K, which was filed with the SEC on March 4, 2021, our 2021 Annual Report on Form 10-K, which will be filed soon, as well as our other SEC filings for a listen for a listing of factors that could cause actual results to differ materially from expected results. Please also note that on this call, we use the terms EBITDA, adjusted EBITDA and distributable cash flow. These are non-GAAP financial measures and we've provided reconciliations to the most directly comparable GAAP measures in our most recent earnings release.

And with that, I'll turn the call over to Heath.

Thanks, Ross. Good morning, everyone, and thank you for joining our earnings call. So I'd like to start off by providing a recap of 2021, as we certainly had a lot going on throughout the year. So first, Summit reported full-year adjusted EBITDA of $238 million, ending the year at the top end of our $225 million to $240 million guidance range and exceeding the midpoint of our original $210 million to $230 million guidance range by nearly 10%. And this was an all-hands effort on cost control, achieving some commercial wins, customers hitting and in many cases exceeding their original expectations and general tailwinds from the economic recovery. As a reference point, our original 2021 guidance, assuming 45 to 75 wells, and we ended the year with 95 wells added to the systems. I will elaborate on this further in a few minutes, but we are hopeful that the prevailing commodity price environment will continue to pull forward activity as we progress throughout 2022.

We also successfully placed the Double E pipeline in service in November, we were able to do so safely, and approximately 20% below the original $500 million budget that was established the original FID. I wouldn't -- nearly 90 rigs running in New Mexico today. We're very excited about the near and long-term outlook for this new and very critical gas pipeline system for the northern -- northern Delaware Basin. We also exchanged over [$115 million] of our preferred equity and accrued distributions in the common equity that continues to reduce our overall financial leverage and eliminated over [$70 million] of accrued, but unpaid distributions from the balance sheet. These series of transactions reduced our Series A preferred face value below $100 million, which enabled us to or will enable us to issue unlimited parity preferred equity in the future, which we believe will be an important strategic tool for Summit in the coming years.

We refinanced nearly $1 billion of debt maturities that were coming due in 2022, with a capital structure that provides us the flexibility that we believe we needed to help us navigate an ever evolving and uncertain oil and gas market. We expected that the economic recovery and the pressures placed on our upstream customers would result in an extended U-shaped recovery for Summit, and this capital structure certainly provides us with a multi-year runway and extended opportunity for that recovery to occur.

Now let's dive into 2022 guidance. First off, given the commodity price environment that we're in and the momentum in activity that we experienced during the second half of 2021, we are very disappointed with a limited amount of new wells that our customers latest plans are indicating will be turned online behind our systems in 2022. The guidance range we announced earlier this morning is based on approximately 75 to 110 new wells, which is basically flat to the historically low levels of activity we experienced during the 2021 -- or 2020 and 2021 downturn, and certainly well below our pre-pandemic 3-year average of approximately 260 new wells per year, which as a reminder, were developed during the time when Henry Hub averaged below $3 and WTI averaged below $60 a barrel.

We are obviously now and one of the best commodity price environments that we've seen in quite some time with the WTI strip North of $80 a barrel, approaching $100 and the inner [ebb] strip above $4 for MMbtu. At these pricing levels, we believe that virtually all of the remaining inventory behind our gas and crude systems will be economic to develop. Furthermore, our customers have significantly improved their balance sheets and financial capability through a combination of industry consolidations, restructuring activities, and good old fashion capital discipline over the past couple of years and are now in a much better position to increase development spending to capture what we believe are very high returning compelling opportunities on inventories behind our system.

While we understand that despite the [bolus] commodity price outlook, producer restrain is a continued theme among public companies and even some private companies. These are things that are generally in place to appease investors by holding production flat year-over-year, continuing to strengthen the balance sheet and continuing to return capital to shareholders via share buybacks and distributions. Look, I mean, as a result, upstream equity values are now up, but certainly make buybacks more expensive within free cash flow generation is nearing an all-time high and balance sheets have certainly improved significantly. We think these factors as we continue to progress into 2022 and the fundamentals hold, we think that, that will support a compelling case for producers to eventually begin increasing development budgets to grow production and to gain further confidence that the fundamentals that we're experiencing will continue to support a healthy commodity price environment going forward.

Now to add some commentary -- segment level commentary, let me -- let me start off in the Rockies. So the majority of that 20 to 30 new wells that we're currently expecting in this segment for 2022 is in the Williston Basin, and it's primarily being driven by private producers behind our Polar and Divide liquids [system] While activity levels are well below historical pre-pandemic levels and certainly below what we would expect them to be in this pricing environment, we continue to be excited about the oil results we are seeing in Central Williams County with nearly 30 new wells having been brought online since 9/30 of last year. More broadly, activity in the Bakken continues to shift Westerly towards our footprint as producers deplete top tier inventory in Southern Williams and McKenzie County, and in particular within the Fort Berthold region.

I'm also pleased to announce that we recently secured a new 50,000 acre dedication with a customer that has acreage located in close proximity to our Polar and Divide system. And we think this new dedication could be a significant catalyst for volume growth as this acreage becomes further delineated in 2022 and 2023.

Moving to the DJ, we have very little activity plan behind our systems in 2022. We think this is largely attributable to the producer restraint thesis that I highlighted earlier in the year or in the call. But another factor that we think is impacting our near-term outlook is the recent consolidation activity in the basin. One of our large anchor customers in the DJ was acquired last year by a company that has recently completed 5 large-scale acquisitions to effectively consolidate the basin over the past 18 months. While longer term, we expect this will be a net positive for our DJ acreage position, the successor company appears to be focusing its near-term development activities on acreage in a more densely populated areas within the DJ. We do expect them to return to development activity on our footprint as these areas get more fully developed. And look, but in the near term we are making progress on offload agreements with other processes -- or processors in the area that we think can help us improve our outlook in the DJ as we wait on that development activity to pick back up within our dedicated footprint.

Now quickly to hit on the Piceance, we had 9 wells come online during the fourth quarter, which really represent the first wells on the system in more than 3 years now. We have another 70 wells slated for 2022, and we have recently entered into a capital reimbursement agreement with a customer that would enable us to begin system planning activities for another 74 wells that we think could be brought online behind our systems in the 2023 to 2024 timeframe.

In the Barnett, we expect at least 4 wells behind the system in 2022, and have -- and are having conversations for up to 7 additional wells in the second half. The 70 wells brought online in 2021 were some of the best performing -- were the best performing wells connected to the system thus far, and we believe that our customers are responding to improving natural gas prices and we'll continue to be active longer term in this pricing environment.

Now shifting to the Permian, we remain very optimistic with the long-term outlook for Double E. As a reminder, we placed the pipeline in service with initial capacity to transport an incremental 1.5 Bcf a day of natural gas from growing reduction in Eddy and Lea County, New Mexico, to interconnect with multiple Gulf Coast oriented pipelines that originate out of Waha, Texas. Double E is anchored by 1 Bcf a day of long-term take-or-pay contracts from some of the largest producers in the Permian Basin and is very well positioned for a highly efficient expansion to 2 Bcf a day as production continues to ramp up in the area. We expect Double E will be a significant growth catalyst for Summit as our initial Bcf a day of sculpted take-or-pay contracts ramp up between 2022 and 2024, and as we secure new contracts from Northern Delaware customers that need incremental gas takeaway capacity to enable production growth.

Our Permian GMP position continues to be impacted by our primary anchor customers, deferral of activity in and around our footprint and the timing of when that activity on our dedicated acreage will be developed by this customer does remain uncertain, but we are encouraged to see private producers adjacent to our system beginning to ramp-up activity levels. And we do expect that some of this volume will find its way to our system through various offload agreements as processing capacity in the area becomes more scarce in the future. We also believe that we will be successful in securing the contracts with other customers in this area and that we are beginning to see that our planning development activity in and around the [Lane] system footprint.

And then finally in the Northeast, we are currently expecting 30 to 44 new well connects in 2022, and this is relative to approximately 50 wells in each of 2020 and 2021. This is -- this lower expected activity for 2022 is in spite of the significant efficiency gains that we've observed through longer laterals and improvement in completion techniques, which have driven really record well performance out of the Utica, and behind our systems. Again, we believe that the producer restraint thesis is in play here despite the highly attractive returns that can be achieved in this -- in this gas price environment.

Additionally, one of our primary anchor customers behind our wholly owned SMU system in the Utica has publicly indicated their interest in divesting its acreage position in the basin. This customer has been virtually inactive in the Utica for the past several years and as well this acreage could really become a significant catalyst for future incremental development activity in our Northeast segment in the coming years.

So with that, I'd like to hand the call over to Bill now to let him provide some additional details on our financial results and outlook. Bill?

Thanks, Heath, and good morning, everyone. First off, I'd like to say that I'm excited to serve as our stakeholders new CFO, and would also like to thank Marc Stratton, a good friend and mentor over the past 6 years for really helping me be in a position to take on this important responsibility. I'll continue to do everything in my control to maximize value to all our stakeholders.

As Heath mentioned, we had a good year, and I'll start by discussing our quarterly financial performance, followed by adding a little more color on our 2022 guidance. As you all may have noticed in our earnings release, we have streamlined our segment reporting to better align how we manage our business and how macroeconomic trends tend to impact our areas of operations.

And with that, starting in the Northeast, which is inclusive of our SMU system, proportionate share of our Ohio Gathering joint venture and our Marcellus system, the segment average 1.24 Bcf per day during the quarter, which is inclusive of 530 million a day of [8/8] OGC volumes and segment adjusted EBITDA totaled $19 million, which was down by 1.7 million from the third quarter. The variance was largely due to natural declines of wells on the system, partially offset by 16 new wells brought online during the quarter, of which 4 were connected directly behind our Wholly owned Utica system in November. These 4 wells IP-ed at 100 million a day -- 100 million a day, which was in line with our internal expectations and represented another set of wells that IP-ed north of 20 million a day behind our system.

The Northeast segment currently has 15 DUCs, which represents approximately 50% of our expected well connections in 2022. The Rockies segment, which is inclusive of our DJ and Williston Basin systems generated adjusted EBITDA of $14.9 million, which was down by $3.8 million from the third quarter, largely due to $1.8 million dollar benefit related to the settlement of a legal matter with a vendor in the third quarter. Liquids volumes averaged 62,000 barrels a day, a decrease of 1,000 barrel a day from the prior quarter and natural gas volumes averaged 34 million a day, a decrease of 2 million a day relative to third quarter. This was primarily due to natural production declines, partially offset by 16 wells that were connected behind our crude oil system late in the quarter.

The Rocky segment currently has 11 DUCs, or wells already online in 2022, which represent approximately 54% of our expected well connections in the year. The Permian Basin segment, which includes our wholly owned Lane GMP and our 70% interest in Double E -- in the Double E Pipeline reported adjusted EBITDA of $2.6 million, representing a $2.1 million increase relative to the third quarter. This is primarily due to commencing commercial operation of the Double E Pipeline during the quarter. Volumes averaged 24 million a day behind our GMP system, flat versus the third quarter and Double E volumes averaged 124 million a day on an 8/8 basis for the quarter, while online, with flow beginning on November 18.

No new wells were connected behind our GMP asset during the quarter. But as of year-end, we had 4 DUCs behind our GMP system, which represent the only direct well connects we expect at this juncture for calendar year '22. As Heath mentioned, there are significant development activity adjacent to our system, which we expect will result in incremental volumes through existing offload agreements. In addition, some dedicated acreage was recently sold to 2 very active private producers in the area, which have 8 active new drill permits today. We continue to discuss potential development plans for 2022 and beyond, but are encouraged by this acreage getting in the hands of more active customers.

Lastly, we are encouraged to see M&A transactions like the GCX deal, getting done at multiples estimated at over 10.5x. We think this is a strong signal of the intrinsic value that the Double E Pipeline may accrue to our stakeholders. As a reminder, at full capacity of 1.5 Bcf a day, we expect SMLPs 70% interest in Double E to generate approximately $45 million of EBITDA. And as of year-end, we had $160 million of debt outstanding and $100 million of preferred equity outstanding at our unrestricted subsidiaries.

The Piceance segment reported adjusted EBITDA of $15.9 million, down $3 million relative to the third quarter due to $3.4 million of MVCs that expired in the third quarter. This is partially offset by the 9 wells that came online during the quarter, which as Heath mentioned, we're the first wells behind the system in over 3 years. Volumes averaged 317 million a day, a slight increase relative to the third quarter and there are no DUCs behind the system currently, but we expect one of our customers to mobilize its active in basin rig to drill 17 permitted wells during the summer. This customer has also stated initial plans for over 70 wells in 2023 and 2024, which is reflective of the strong natural gas and NGL commodity price environment we see ourselves in.

The Barnett segment reported adjusted EBITDA of $10.2 million, an increase of $0.6 million relative to third quarter, primarily due to the 7 new wells brought online late in late September, which increased volumes from 201 million a day to 222 million a day in the fourth quarter. As Heath mentioned, these wells were the best wells we've ever seen on the system and are a direct result of the technological improvements producers are implementing into their GNC programs. These wells IP-ed at 7 million a day each and as of today are flowing around 5 million a day each after 3 months of production.

Given natural gas prices and the proximity of the Barnett to the Gulf Coast and LNG export market, we are excited about the prospects for additional development behind the system that the Street has likely written off as a PDP decline asset. There are currently 4 DUCs behind the system, which represent all the wells we expect at the low end of our guidance range. However, we are active in discussions with our customers regarding an additional 7 permitted wells that we have included in the high-end of our guidance range.

Quickly on the partnership, SMLP reported a fourth quarter net loss of $16.2 million and adjusted EBITDA of $54.7 million. We recorded an impairment of $8.4 million dollars during the quarter, primarily due to certain latent inventory that we have sold or may sell. This is part of a corporate initiative to maximize free cash flow and pay down debt through a continued focus on inventory management and asset rationalization. Capital expenditures totaled $13.3 million for the quarter, which was $7.4 million higher than the third quarter and included $3.2 million of maintenance capex. The majority of the capex during the quarter was associated with growth capital to connect new pad sites in our Utica, Permian and Williston systems. During the quarter, we also invested $6 million into Summit Permian Transmission Holdco, which we believe will satisfy the vast majority of [investible Ps] remaining net investment in Double E during 2022.

With respect to SMLP balance sheet, we had $267 million outstanding under our $400 million ABL credit facility, and we have repaid an additional $17 million of debt to date with free cash flow generated thus far in 2022. Our available borrowing capacity at the end of the fourth quarter totaled approximately $109 million, which included $23.9 million LCs. As we close out the remaining cost at Double E, we would expect a significant amount of those LCs to fall away, which, in addition to expected debt repayment, will increase our liquidity throughout the year.

With that, I'd like to add some detail on Heath's comments on our 2022 guidance. As we discussed last year, the midpoint of our guidance range risk, the timing of well connections by a few months and risk IP rates relative to what customers have provided, the low-end will resolve that even further, and the high-end assumes customers hit their timing and IP targets. We continue to believe this is a prudent methodology for setting expectations and balance sheet planning given the evolving dynamics impacting our upstream customers that Heath already alluded to. Looking backward for a moment, our 2021 outperformance was a result of our customers hitting their targets and that's SMLP benefiting from a handful of tailwinds that pushed us nearly 10% above the midpoint of our original guidance. We hope that we experience similar tailwinds in 2022, but we can't rely on it when making decisions and informing our stakeholders of the near-term outlook as we see it today.

A few final points, in our 2022 guidance range we included $5 million of onetime operating expenses related to certain asset integrity and regulatory initiatives. In addition, there is approximately $6 million of similar maintenance capex expenditures included in our capex range. We believe these investments will better position SMLP for upcoming regulatory changes, reduce our emission profile and ensure that our assets are protected and while maintained for many years to come. We will continue to focus on cost control and doing everything in our control to combat inflationary pressures. We are also laser-focused on only making growth investments that generate an attractive risk-adjusted return for all our stakeholders. And as always, we will promise to be transparent as things progress throughout the year.

And with that, I'll turn the call back over to Heath for closing remarks.

All right, yes, thanks, Bill. So look, again, we are obviously disappointed with limited activity that our customers latest plans indicate for us for 2022, but we do remain optimistic and really encouraged by the fundamentals that we believe will ultimately result in producer activity levels trending back up across our systems. Admittedly, we anticipated that 2021 would be the trough year for Summit and that the U-shape recovery would begin as we moved into 2022, and that was particularly driven by fundamentals and commodity prices that continue to strengthen last year and into the first quarter of this year.

We were, however, mindful of the risks and timing and uncertainty that, that could potentially lengthen the timeframe for that would allow a U-shape recovery to occur for Summit and its customers and that was really a key objective in our 2021 refinancing strategy, which was to ensure that we established a multi-year runway that would allow the business outlook to recover and strengthen and we continue to expect that it will do so over time.

As was the case last year, we could see customers increase their plan activity levels later in the year, and we will provide updated 2022 guidance accordingly to the extent we expect the outlook to be materially different than our initial guidance range. In the meantime, we will certainly do everything in our control to continue to maximize free cash flow, pay down debt, and position the company and our stakeholders for success going forward. We will also continue to provide safe, efficient, reliable, and sustainable operations for our customers, while we also maintain a very positive and safe work environment for our employees and our contractors. I'd like to thank everyone for their time and continued support.

And with that, operator, I'd like to open the call up for questions.

(Operator Instructions) And from U.S. Capital, we have James Carreker.

Just wondering, does this latest outlook in any way affect any covenants or leverage restrictions that might have been in place on the new debt financing that you completed last year?

Yes, hey, James, this is Bill. No, we -- that was really a key consideration as we thought about the refinancing package and putting a covenant-light package in place and really think about the covenant package really being limited to minimum interest coverage of 2x and then a first lien secured. So think of that as the ABL a max leverage of 2.5x. And based on this guidance range, we expect to be in compliance with both of those throughout the course of 2022.

Got you. And then maybe just thinking broadly, if I'm remembering right, a lot of the systems were built with strong MVC protection. So I guess thinking about the decline year-over-year, how much of that is kind of MVCs rolling off? How much of that is kind of production declines? Is there any way to kind of bucket that?.

Yes, sure.

Yes, the follow-up to that is kind of what does the MVC roll off situation look like '23 and beyond?

No, it's a great question and I would point you to kind of focus on that MVC shortfall payments section within our guidance. And if you kind of track that over the quarters, you'll notice in the Piceance, we had about a $3.2 million decline from the third quarter to the fourth quarter. That was one particular MVC that, that basically expired at the end of the third quarter. So on an annualized basis, think of that as a $13 million roughly decline from 2021 to 2022. So that's the primary variance kind of year-over-year. And if you look kind of at that table in 2021 for a full year basis, we had about $51 million worth of shortfall payments. And how we've been generally describing that is, think of that is, call it $10 million reductions over the next, call it, 3 or 4 years until that effectively expires, I think our last MVC in 2026.

That's helpful. And then if I could maybe fit in another one, just kind of curious, excuse me, just on the Double E throughput outlook. I guess, just any commentary on maybe why that's maybe like about half of what I think is contracted for 2022.

Look, a lot of that is going to be dependent, right? The pipe just became operational in November. Those are annual averages. We would expect that throughout the course of the year, we start approaching from a usage perspective closer to the [585 million] a day of kind of contracted capacity in year 1. And as a reminder, that sculpts and increases such that by November of 2024, those contracts will be fully ramped at 1 Bcf a day, which is the existing contracts. So producers, obviously, they expect to lag in to those contracts. That was part of the initial planning. That's why they ramp contractually. And I do expect, given the rig activity out there, I mean, we're seeing 90-plus rigs running in New Mexico. That's an asset that we're very bullish on right now. And if you think about the existing contract profile at a Bcf a day, fully ramped, we think that's going to do somewhere around $30 million of EBITDA. And as I mentioned in my prepared remarks, fully contracted at [135] we'd expect kind of the EBITDA to be around $45 million, net to Summit.

And just as a reminder, that -- when we talk about Double E and the volumes, I mean, these are virtually 100% take-or-pay type contracts. So there's really very little revenue associated with just throughput. It's all based on demand charges and the contracted capacity that Bill just walked you through.

That's helpful. And I guess, just one more. I guess, as you look forward, you've obviously got the ramp in Double E. I guess, what area would you have the most optimism in reinvigorating some level of growth as we look to 2023? What early discussions are there with producers that would indicate that we're really excited about the Utica or what...

Yes. No, it's a good question. And let me -- maybe let me just frame it. As we tried to frame it on the earnings call, I would say so long as we're in a, call it north of $3 and north of $60 crude, there's really not a well behind our system that would not be economic to drill. Obviously, a lot of people could say that in the U.S. shale, I mean, that kind of certainly at that pricing level, you get beyond the vast majority of the breakevens and into good returning wells. Where we see just specifically in that kind of price environment, I think what, frankly we were most surprised about was that we didn't have a stronger Utica outlook for 2022. We've got 3 main customers there that drive the needle, Ascent, who's been very active in the basin and frankly has been delivering some monster wells. We've got XTO, who has been very public about their desire to monetize their acreage position in the Utica. And then we have Gulfport, who recently just came out of restructuring, and I'm sure they're trying to figure out what's next for them. So I'd say 2 out of the 3 have not been active in the past couple of years has since been driving most of the volumetric growth behind our systems, both the OGC system and our SMU system. So I think in this -- look, these wells are -- we've seen more well activity when prices were $250 and what we're seeing right now where prices are $450-plus.

So economically, I think there's no doubt that if prices -- if people get comfortable in the fundamentals that, hey, not just right now, but if you look out over the next 3 to 4 years, that prices are going to be anywhere north of $3, I think that should support a very significant step-up in drilling and development plans. And I would say if XTO allowing the [depth], they're important customers in 3 basins for us. If they're successful monetizing that position, I think someone stepping into that position and getting back to drilling could be very meaningful for years to come. So I put Utica up there is probably very high. I'd say the Williston, we had 30 wells come online, really since the September and the second half activity is very muted right now. I'd say we -- our private producers have kind of -- they're not doing anything heroic, but most of the wells that we're projecting for 2022 are from the private side. We've got a large customer that acquired Bruin out of bankruptcy and -- or I guess it was during -- was it during or after bankrupt. Anyway, right after bankruptcy. I would say not that producer right now, it's public guys, is just not active on our footprint. They're drilling out there for [Berthold] reservation acreage. We'll see whether or not they continue to -- when they come back into our area, but we've got a very expansive set of inventory up there that's highly economic at, call it, anywhere in the 60-plus range, it should support healthy drilling activity. So I think those are probably the 2 areas that I'd say, I would -- I think we should see well connects potentially double if not triple in this price environment. And that would basically just get them to the same levels that they were at kind of pre-pandemic where all a sub-60 and gas was sub $3. So those are the 2. I'd say the other area that we're kind of -- is an anomaly is the DJ, just given the economics. As we said on the call, virtually all of our Rockies segment, which is now DJ and the Bakken, but virtually all of the activity we're projecting in 2022 is in the Bakken, which means we have maybe 1 or 2 wells in the DJ. Our 2 primary customers there are Civitas and EOG, neither of which for this year have a rig active on our acreage position. Clearly, we've had as many as 100 well connects per year. We've got plenty of inventory up there. In this price environment, we think they're highly economic to develop. And we're hopeful. I mean, I think EOG being the public guy, and I'm sure they're sophisticated enough not to just go out there and chase prices. But I think if the fundamentals support it, they certainly view this acreage to be highly economic, and we know that they're going to get to it in time. But that is an area that we would expect to see step up. And frankly, we're surprised that we have very little to no activity on.

Yes, the other thing, James, just to add. As we think about the -- even the Barnett and the Piceance, I mean we're seeing activity, particularly in the Barnett, just at these gas prices, fairly consistent activity. Now that may not grow production. And if you look at kind of the ranges, it will give you a general sense of kind of relative to 2021 kind of calendar year, volumetric figures for the Barnett. We don't need much to kind of hold that system flat. And I think a lot of folks view that as, call it a 10% PDP decline type asset. And similarly, in the Piceance, those are smaller wells. But again, if you think about that level of activity kind of stemming your more traditional PDP decline, that's very incremental to Summit. And the only other thing I'd add up in the Utica as Heath mentioned, with XTO and that acreage position, that was developed in a period kind of the old school period, right, where you put down 1 or 2 wells on a pad to hold the lease and then come back in and infill drill. So a majority of the inventory behind that acreage is already connected and would require fairly limited capex net to Summit, and very incremental to the free cash flow profile.

(Operator Instructions) And from Bank of America, we have Gregg Brody.

A lot of good questions asked there also by the previous analysts. Just wanted to touch base on a couple of follow-ups there. So just the Utica, I appreciate that if assets end up in different hands, they could be developed. I'm curious if -- what you -- how do you think about the takeaway capacity there just to get gas out of basin? Or is there a demand in basin for ramp in gas?

Yes, I think the short answer, we feel pretty comfortable that there's takeaway out of the basin. We also think of these elevated prices on a basis adjusted basis, net to the wellhead, there's still highly economic to drill. So I don't think that we would see takeaway capacity being a long-term issue as it relates to our footprint.

Do you have a sense of the quantity of spare capacity there or just billing this gas?

I mean the short answer is, I mean, I don't have a specific number that I can give you. I think what's -- what we've seen in the past is we've seen production out of the Utica higher than where it is today. We know that there has been takeaway capacity that's been built out. Usually, what happens is, at some point, you do get gas-on-gas pricing competition that could drive the basis down. But I don't think we've ever been in a spot to where we physically had to shut in gas or was unable to move gas out. The question is at what price. And the point being, at times we've seen 2.25 maybe even below 2.25 on a basis adjustment standpoint. And it still made sense for some incremental wells to kind of come online. So we think we have enough headroom, and we think we have enough takeaway capacity. This really in our opinion gets down to kind of a -- we feel like it's somewhat of an anomaly here with the Utica just given what the returns would be for incremental wells that would come online. We're hopeful that whether it's the XTO position, whether it's Gulfport starting to put some rigs to work or Ascent, private guy up there just starting to step up in their development plan, they're actually running fewer rigs in 2022 than they were in 2021 in the basin. And part of that could just be a timing disconnect and I can't speak for them, but I just -- what I can say is that Utica is an area that really should just be getting drilled and drilled pretty hard right now.

Okay. And then you talked about the Permian, there being a lot of activity there. Just for the potential part of Double E that's not contracted, adding capacity -- adding a contract there, do you have any line of sight as to how long that will take? Any updates there that are relevant that this is something that could happen this year?

Yes. I mean, I think, look, I would say that if you look at New Mexico and you look at the fact that there are really -- this is the only new infrastructure that's been placed in service. You look at the rigs, you could easily start seeing in 2023 there being a problem getting gas out of New Mexico. XTO is obviously forward thinking on that, and that's why Double E was so strategic that they were a 30% partner and why they took a pretty substantial, call it, 750 million a day position out of that Bcf a day to make sure that they had that takeaway secured. Some producers are -- and a lot of the privates tend to be more sell my gas at the wellhead and at times maybe they lag a little bit until they see some price signal that suggests they need to have transport. And we think that price signal could show up as early as 2023.

Now I will say the way that we think about it, we do have conversations ongoing now. And whether we -- we'll probably see some interruptible gas, maybe some short-term contracts, some optimization type revenues that we can kind of get done here over the next couple of years. But I think by 2024, if this thesis continues to play out, we continue to see rig activity and growing production. I would be surprised if we weren't able to get the [1.35] fully subscribed here between now and 2024. Now could ramp up a little bit. We -- that's yet to be determined, but it's hard for us to see how that doesn't happen just given the trajectory of volumes.

And the other point is that we see not only just that 1.35, but we've got a very inexpensive basically at a mainline compressor station on existing Double E to be able to take that up to 2 Bcf a day. And if what we think is going to happen is going to happen, that's going to be the most cost-effective, most timely way to debottleneck New Mexico if we get that compression up and down. Now that will require for process and something that we're going to be -- as we talk today with customers, we're trying to anticipate is that something that we want to start moving forward with now that we've got the Phase I -- the main pipeline in service.

Got it. And then just the, in terms of -- I know the term loan is drawn there at Double E at that JV. Just if you think about, any thoughts, it's pretty much just paying that down right now. Are there any plans to address the preferred or the term loan in some way that could change the capital structure at all?

Yes. I mean, Gregg, we're going to -- well, let me answer it this way, I guess. So the credit agreement down there, the term loan actually has embedded expansion capabilities. So if we do get incremental contracts, depending whether they're investment grade or noninvestment grade, we can actually expand that facility size bit effectively, take a distribution which could then be used to service the preferred. We're obviously very cognizant that the structure results in fairly limited cash flow back to SMLP, but it's also a very attractive capital, attractively priced. It's cash paid on the preferred at 7% and the bank deal down there, the term loans at L plus [237.5]. So very, very attractive pricing. And I think you would see us potentially look at recapping that once we get another decent size long-term contract. And I think that's just an ongoing kind of assessment.

And again, as this -- as Double E is generating this free cash flow and distributions are paid to that chain, it does kind of outlined $160 million outstanding at year-end on the term loan and then $100 million on the pref. We're going to be paying both of those down over the course of this year, next year and beyond. So as you think about accruing and growing that residual equity value kind of net to Summit, that's all going to be taking place whether we generate actual cash flow to SMLP or not.

That makes sense. And you touched on my next question. So you think there's a possibility you could take a dividend at some point that helps pay down preferred. Could you talk a little bit about that and how much you can do? And just how are you thinking about the preferred? Is there a sense that the equity exchange opportunity is -- you've played that [out of the door]?

Look, I think the barbell is -- I'll just give you the barbell. If we did [350 million] a day with an investment-grade off-taker for a 10-year contract, that would probably expand the bank deal by roughly $100 million.

Is that -- do you think you could take all that -- I mean, you probably would need some of that to fund down there, right? So how much do you think you -- how much you...

I'm saying that, that would be the incremental borrowing capacity with that incremental contract. So a majority of that we'd be able to distribute up and service the TPG price.

Got it. And any other ways that you're thinking about today to address that as the equity exchange game still a tool? Or do you feel that that's paid out?

On the Double E side, I think -- I think we like the capital structure we've got in place at Double E at the moment.

I'm referring to the preferred at Summit. Oh, got it. Got it.

Look, we've -- on the preferred, we've done, what, 3 or 4 exchanges already, Gregg. So if you think about kind of just the diminishing returns, I suspect that the majority of the investors that are left in that preferred probably want to stay there. But the critical strategic point of that was getting it below $100 million of face value, which opens up our ability to issue parity preferred to the extent something strategic comes about or kind of other opportunities.

Got it. And then maybe you could talk a little bit about -- you talked about maybe pruning some assets in the press release. You talked about how much you think that could be this year. And then can you talk about the M&A opportunity for you -- the acquisition opportunity for you?

Sorry, I didn't catch the first -- your first...

You mentioned in the press release you might prune some assets like you did this year. Do you have a sense of how much that could be?

No. I think -- look, I mean, what I would say -- we've said this for a couple of years now. I mean, we're very mindful, I mean, on the positive side I think we certainly have seen M&A pick up a bit, where there's been a few deals that have gotten done. If we see an opportunity, an actual opportunity to acquire or divest of an asset that we think makes sense and is done at an attractive value. We're going to look at it. I mean, our focus is on the balance sheet. And it has been since I started and it continues to be today. And in the event that we can accelerate delevering and strengthen the balance sheet on a transaction, you bet we'd do it. But I don't think it's worth speculating. I mean, we've got our feelers out on a lot of stuff right now and who knows, but we'll certainly -- I just wanted to let you know at least the mindset of the management team and the Board is to -- if there's an opportunity to transact on a credit-accretive basis, we're going to do it, whether that's on the buy side or the sell side.

Yes. And Gregg, we -- so last year we sold kind of $8 million roughly of kind of latent inventory. Think of that as just compressors -- compressors, we weren't using in other kind of assets like that, that we're sitting in the inventory. We sold about $2 million of that so far this year. So there could be some nickels and dimes throughout the course of the year as we continue to kind of optimize our inventory and latent inventory.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for joining. You may now disconnect.