Summit Midstream Corporation

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 at this time all participants are in a listen-only mode later we will conduct the question and answer session during which you may dial star 1 if you have a question 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.summitministry.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 Malt, 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 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 have provided reconciliations to the most directly comparable gap measures in our most recent earnings release. And with that, I'll turn the call over to Heath.

Thanks, Ross. Good morning, everyone. 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 to $240 million guidance range, and exceeding the midpoint of our original 210 to 230 million guidance range by nearly 10%. 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 assumed 45 to 75 wells, and we ended the year with 95 wells added to the systems. I'll 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 W pipeline in service in November. We were able to do so safely and approximately 20% below the original $500 million budget that was established at original FID. With 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 Delaware Basin. We also exchanged over $115 million of our preferred equity and accrued distributions into common equity that continues to reduce our overall financial leverage and eliminated over $17 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 a billion dollars 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, you know, given the commodity price environment that we're in and the momentum and activity that we experienced during the second half of 2021, you know, 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 2020 and 2021 downturn, and certainly well below our pre-pandemic three-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're obviously now in 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 interheb strip above $4 for MMVTU. 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-fashioned 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 return and compelling opportunities on inventories behind our system. While we understand that despite the bullish commodity price outlook, you know, producer restraint is a continued theme among public companies and even some private companies. These are themes 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. We think 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 as they 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 start off in the Rockies. So the majority of the 20 to 30 new wells that we're currently expecting in this segment for 2022 is in the Willison Basin. And it's primarily being driven by private producers behind our polar and divided liquid 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 well 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, 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. 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 planned behind our systems in 2022. We think that this is largely attributable to the producer restraint thesis that I highlighted earlier 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 five 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 the 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, in the near term, we are making progress on offload agreements with other 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 peons, we had nine wells come online during the fourth quarter, which really represent the first wells on the system in more than three years now. We have another 17 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 four wells behind the system in 2022 and are having conversations for up to seven additional wells in the second half. The 70 wells brought online in 2021 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 will continue to be active longer term in this pricing environment. Shifting to the Permian, we remain very optimistic with a long-term outlook for EE. As a reminder, we've placed the pipeline in service with initial capacity to transport an incremental 1.35 BCF a day of natural gas from growing production in Eddie and Lee County, New Mexico, to interconnect with multiple Gulf Coast-oriented pipelines that originate out of Oaxaca, Texas. W is anchored by one 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 two BCF a day as production continues to ramp up in the area. We expect EE will be a significant growth catalyst for Summit as our initial VCF-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, 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. 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 new contracts with other customers in this area. that we are beginning to see that are 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 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 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 anchorage position in the basin. This customer has been virtually inactive in the Utica for the past several years, and the sale of this anchorage 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 stakeholder's new CFO, and would also like to thank Mark Stratton, a good friend and mentor over the past six 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 averaged 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 four were connected directly behind our wholly owned Utica system in November. These four wells IP'd at 100 million a day, which was in line with our internal expectations and represented another set of wells that IP'd north of 20 million a day behind our system. The Northeast segment currently has 15 docks, which represents approximately 50% of our expected well connections in 2022. The Rocky segment, which is inclusive of our DJ and Willison 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 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 barrels 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 ducts or wells already online in 2022, which represent approximately 55% of our expected well connections in the year. The Permian Basin segment, which includes our wholly owned Lane GMP and our 70% interest in the EE pipeline, reported adjusted EBITDA of $2.6 million, representing a $2.1 million increase relative to third quarter. This is primarily due to commencing commercial operation of the EE pipeline during the quarter. Volumes averaged $24 million a day behind our GMP system, flat versus the third quarter, and EE volumes averaged $124 million a day on an 8-8 basis for the quarter while online, with flow beginning on November 18th. No new wells were connected behind our GMP asset during the quarter, but as of year end, we had four docks behind our GMP system, which represent the only direct well connects we expect at this juncture for calendar year 22. As Heath mentioned, there is 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 two very active private producers in the area, which have eight 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 10.5 times. We think this is a strong signal of the intrinsic value that the EE pipeline may accrue to our stakeholders. As a reminder, at full capacity of 1.35 BCF a day, we expect SMLP's 70% interest in EE 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 peon segment reported adjusted EBITDA of $15.9 million, down $3 million relative to third quarter, due to $3.4 million of MVCs that expired in the third quarter. This was partially offset by the nine wells that came online during the quarter, which, as Heath mentioned, were the first wells behind the system in over three years. Volumes average $317 million a day, a slight increase relative to third quarter, and there are no ducts 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 seven new wells brought online 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 this system. and are a direct result of the technological improvements producers are implementing into their DNC programs. These wells IP'd at $7 million a day each, and as of today, are flowing around $5 million a day each after three 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 a system that the street has likely written off as a PDP decline asset. There are currently four docs behind the system, which represent all the wells we expect at the low end of our guidance range. However, we are active discussions with our customers regarding an additional seven 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 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 S&P's remaining net investment in EE during 2022. With respect to SMLP's 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 of LCs. As we close out the remaining costs at EE, 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 risks the timing of well connections by a few months and risks IP rates relative to what customers have provided. The low end risks all 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 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 finer points. In our 2022 guidance range, we have included $5 million of one-time operating expenses related to certain asset integrity and regulatory initiatives. In addition, there's 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 well 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. Yeah, thanks, Bill. So look, again, while we're obviously disappointed with the 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 turning back up across our systems. Admittedly, we anticipated that 2021 would be the trough year for Summit and that the U-shaped recovery would begin as we moved into 2022, and that was particularly driven by fundamentals and commodity prices that continued to strengthen last year and into the first quarter of this year. We were, however, mindful of the risks and timing uncertainty that, you know, that could potentially lengthen the timeframe for, you know, that would allow a U-shaped 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, you know, 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 and 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 the time and continued support. And with that, operator, I'd like to open the call up for questions.

Thank you, sir. We'll now begin the question and answer session. If you have a question, please dial star 1 on your phone keypad. If you'd like to be removed from the queue, please dial the pound sign or the hash key. If you're on a speakerphone, please pick up your handset first before dialing. Once again, if you have a question, please dial star 1 on your phone keypad. And please hold for a moment while we assemble our queue. And from U.S. Capitol, we have James Carriker. Please go ahead.

Good morning, guys. Thanks for the call. 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?

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

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

Yeah, sure.

And I guess, yeah, the followup for that is kind of, you know, what does the NBC roll off situation look like, you know, 23 and beyond? Yeah.

No, it's a great question, and I would point you to kind of focus on that MVC shortfall payment section within our guidance. If you kind of track that over the quarters, you'll notice in the peons, we had about a $3.2 million decline from the third quarter to the fourth quarter. That was one particular MVC 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, you know, 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, you know, think of that as, call it $10 million reductions over the next, call it three or four years, until that, you know, effectively expires. I think our last MVC is in 2026.

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

Yeah. 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, you know, we start approaching from a usage perspective closer to the $585 million a day of kind of contracted capacity in year one. And as a reminder, you know, that sculpts and increases such that by November of 2024, those contracts will be fully ramped at one BCF a day, which is the existing contracts. So, you know, producers, obviously, they expect to leg 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. You know, that's an asset that we're very bullish on right now. And, you know, 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 earlier, fully contracted at 135, we'd expect the EBITDA to be around 45 million, net to summit.

Just as a reminder, when we talk about EE and the volumes, 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 the bill just walked you through.

That's helpful. I guess just one more. I guess as you look forward, you've obviously got the rampant EE. 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

Yeah, no, that's a good question. And 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, the A lot of people can 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 break-evens 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 three 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 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. You know, I'd say two out of the three have not been active in the past couple of years and since been driving most of the volumetric growth behind our systems, both the OGC system and our SMU system. So I think, you know, in this – look, these wells are – we've seen more well activity when prices were $250 than what we're seeing right now where prices are, you know, $450 plus. So economically, I think – There's no doubt that if prices, if people get comfortable in the fundamentals that, hey, you know, not just right now, but if you look out over the next three to four years, that prices are going to be, you know, anywhere north of $3. I think that should support a very significant step up in drilling and development plans. And I would say, you know, if XTO, we love them to death, they're important customers in three basins for us. You know, if they're successful monetizing that position you know, I think, you know, someone stepping into that position and getting back to drilling could be very meaningful for years to come. So I put Utica up there as probably, you know, very high. I'd say the Williston, you know, we had 30 wells come online really since September, and the second half activity is very muted right now. You know, I'd say our private producers have kind of know 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 that acquired bruin out of bankruptcy or and or i guess it was during was it during or after bankruptcy anyway after bank right after bankruptcy um i would say you know not that that producer right now it's a public guy is just not active on our footprint um they're drilling out there for birth hold reservation acreage, you know, we'll see whether or not they continue to, you know, when they come back into our area, but we've got a very expansive set of inventory up there that's highly economic at, you know, call it, you know, anywhere in the 60 plus range, it should support, you know, healthy drilling activity. So I think those are probably the two areas that I'd say, you know, I would, I think we should see, you know, 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, you know, oil was sub-60 and gas was sub-$3. So those are the two. I'd say, you know, the other area that we're kind of is an anomaly is the DJ, just given the economics. You know, as we said on the call, virtually all of our Rocky segment, which is now DJ and the Bakken, but, you know, virtually all of the activity we're projecting in 2022 is in the Bakken segment. which means we have maybe one or two wells in the DJ. Our two 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 you know, they're sophisticated enough not to just go out there and, you know, and chase prices, but I think if the fundamentals support it, you know, they certainly, you know, 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, you know, we would expect to see step up, and frankly, we're surprised that we have very little to no activity on.

Yeah, and the other thing, James, just to add, you know, as we think about the even the Barnett and the Pionts, I mean, we're seeing activity, you know, particularly in the Barnett, just at these gas prices, you know, fairly consistent activity. Now, that may not grow production. And if you look at kind of the ranges, it'll give you a general sense of kind of, you know, relative to 2021 kind of calendar year volumetric figures for the Barnett. you know, we don't need much to kind of hold that system flat, and I think a lot of folks view that as a, you know, call it a 10% PDP decline type asset. And similarly, in the peons, 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... with XTO and that acreage position, you know, that was developed in a period, you know, kind of the old school period, right, where you'd put down one or two wells on a pad to hold the lease and then come back in and infill drills. 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.

Appreciate all that, Colin. Thank you.

You bet.

Once again, if you do have a question, please dial star 1 on your phone keypad. And from Bank of America, we have Greg Brody. Please go ahead.

Hey, good morning, guys, and thank you for all the details. A lot of good questions asked there also by the previous analyst. Just wanted to base a couple of follow-ups there. So, Just to Utica, I appreciate that if assets end up in different hands, they can be developed. I'm curious, how do you think about the takeaway capacity there just to get gas out of basin, or is there demand in basin for rampant gas?

Yeah, 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, they're 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 ability to move gas?

I mean, the short answer is I don't have a specific number that I can give you. You know, what we've seen in the past is we've seen, you know, production out of the Utica higher than where it is today. We know that there has been, you know, takeaway capacity that's been built out. Usually what happens is, you know, at some point you do get, you know, gas on gas pricing competition that could drive the, you know, 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, is at what price? And the point being, you know, at times we've seen, you know, two and a quarter, maybe even below two and a quarter on a basis adjustment standpoint. And, you know, 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, you know, takeaway capacity. This really, in our opinion, gets down to, you know, kind of a, we feel like it's somewhat of an anomaly year with the Utica just given, you know, what the returns would be for incremental wells that would come online. And we're hopeful that whether it's the XCO position, whether it's Gulfport, you know, starting to put some rigs to work, or Ascent, you know, a private guy up there, you know, just starting to step up in, you know, their development plan. They're actually running fewer rigs in 2022 than they were in 2021 in the basin. And, you know, part of that could just be, you know, a timing disconnect. And, you know, 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 you talked about the Permian, there being a lot of activity there. Just for the potential part of W 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?

Yeah. I mean, I think, look... I would say that if you look at New Mexico and you look at the fact that they're really, you know, this is the only new infrastructure that's been placed in service. You look at the rigs, you know, you could easily start seeing in 2023 there being a problem getting gas out of New Mexico. XTO was obviously forward thinking on that, and that's why EE was so strategic that they were our 30% partner and why they took, you know, a pretty substantial, call it $750 million a day position there. out of that BCF a day to make sure that they had that takeaway secured. You know, some producers are, and a lot of the privates, tend to be more, you know, I 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, you know, the way that we think about it, you know, we do have conversations ongoing now And, you know, whether we, you know, 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 years. But I think by 2024, if this thesis continues to play out, we continue to see, you know, rig activity and growing production, you know, I would be surprised if we weren't able to get, you know, the 1.35 fully subscribed here, you know, between now and 2024. Okay. Now, you know, it could ramp up a little bit. You know, that's yet to be determined. But, you know, 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, you know, not only just that 1.35, but we've got a very inexpensive, basically add a mainline compressor station on existing EE 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, you know, that's going to be the most cost-effective, most timely way to de-bottleneck New Mexico if we get that, you know, that compression up and down. Now, that will require, you know, FERC process and, you know, something that we're going to be, as we talk today with customers, you know, we're trying to anticipate is that something that we want to start moving forward with now that we've got the Phase 1, you know, the main pipeline in service.

Got it.

And then just the...

in terms of, I know the term loan's drawn there at EE, at that JV. Just to 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?

Yeah, I mean, Greg, 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 non-investment grade, we can actually expand that facility size, 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 very attractive capital, attractively priced. You know, it's cash pay on the preferred at 7%. And, you know, the bank deal down there, the term loans at L plus 237 and a half. So very, very attractive pricing. And, you know, I think you would see us potentially look at recapping that once we get, you know, another decent size long term contract. And, you know, I think that's just an ongoing kind of assessment. And, again, as this, as EE is generating this free cash flow and distributions are paid to that chain, you know, as 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, you know, 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 dividends? Could you talk a little bit about that and how much you think you can do and just how are you thinking about the preferred? Is there a sense that the equity exchange opportunity, you've played that out?

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.

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 wouldn't?

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 press.

Got it. And then... Any other ways that you're thinking about today to address that? Is the equity exchange game still a tool, or do you feel that's played out?

On the EE side, I think we like the capital structure we've got in place at EE. I'm referring to the preferred at Summit.

Oh, got it, got it.

Look, on the preferred, we've done, what, three or four exchanges already, Greg? So, you know... If you think about kind of just the diminishing returns, I suspect that a 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 other opportunities.

Got it. 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 your first comment.

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

No. I think, look, I mean, what I would say, and we've said this for, you know, a couple 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. There's been a few deals that have gotten done. You know, if we see an opportunity, an actionable 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 de-levering 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 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.

Yeah, and Greg, so last year we sold kind of 8 million bucks roughly of kind of latent inventory. Think of that as just compressors we weren't using and other kind of assets like that that were 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.

Great. That's it for me, guys. Thanks for your help. You bet.

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