Q4 2021 Summit Midstream Partners LP Earnings Call
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 a question and answer session during which you may dial star one if you have a question.
I will now turn the call over to Russ walk 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 Dot summit midstream Dot com.
You will find on the homepage events and presentations section work quarterly results section.
With me to do that today to discuss our fourth quarter of 2021 financial and operating results is Heath Deneke, Our President Chief Executive Officer, and Chairman Bill Moore, 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.
Can provide no assurance that such.
Patients will prove to be correct.
Please see our 2020 annual report on Form 10-K , which was filed with the SEC on March four 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'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, Ralph 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.
Out 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%.
This was an all hands effort on cost control, achieving some commercial wins customers hitting and in many cases exceeding the original expectations and general tailwind from the economic recovery.
As a reference point, our original 2021 guidance seen 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. We will continue to pull forward activity as we progress throughout 2022.
We also successfully placed the <unk> pipeline in service in November and we were able to do so safely and approximately 20% below the original $500 million budget that was established the original.
I Wouldnt nearly 90 rigs running in Mexico today, and 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 accrue distributions and the common equity they continue 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.
It's 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 shape recovery for summit and this capital.
Capital structure, certainly provides us with a multiyear 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 and 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, our 2020 in 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.
Average below $3 and <unk> averaged below $6 a barrel.
We are obviously now and one of the best commodity price environments that we've seen in quite some time and with a debit ti's drop north of $80 a barrel approaching 100.
<unk> strip above $4 a barrel.
Btu.
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 our balance sheets and financial capability through a combination of industry consolidations restructuring activities.
Good old fashion capital discipline over the past couple of years and are now in a much better position to increased development spending to capture what we believe are very high returning compelling opportunities on inventories behind our system.
While we understand that despite the bullish commodity price outlook producer restraint 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 continued 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 it gained 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 on a segment level commentary, let me, 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 Williston Basin and is primarily being driven by private producers behind our polar and divide 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 we're all results we are seeing in Central Williams County, with nearly 30, new wells, having been brought online since 930 of last year.
More broadly our activity in the Bakken continues to shift westerly towards our footprint as producers to please talk to your inventory and Southern Williams Mckenzie County, and in particular within the Fort Berthold region.
I'm also pleased to announce that we recently secured a new 50000 acre dedication with a customer that has acreage located in close proximity to our polar and divide system and.
And we think this new dedication can be a significant catalyst for volume growth is 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 restraints thesis that I highlighted earlier in the year or in the call.
But another factor that we think is impacting our near term outlook as 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.
Element activities on acreage in the more densely populated areas within the D. J.
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 nine.
Nine wells come online during the fourth quarter, which really represent the first wells on the system and 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 half.
And are having conversations for up to seven additional wells in the second half.
The 70 wells brought online in 2021, where some of the best performing work, where 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 the long term outlook for <unk>. As a reminder, we placed the pipeline in service with initial capacity to transport an incremental 135 Bcf a day of natural gas from growing production in Eddy and Lea County, New Mexico to.
To interconnect with with multiple Gulf coast oriented pipelines that originate Ottawa, Texas.
Dublin 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 at production continues to ramp up in the area.
We expect <unk> will be a significant growth catalyst for summit is our initial Bcf a day of sculpted take or pay contracts ramp up between 2022, and 2024 and as we secured new contracts from northern Delaware customers that need incremental gas takeaway capacity to enable production growth.
Our Permian G&P position continues to be impacted by our primary anchor customers deferral of activity in and around our footprint at the timing of when that activity on our dedicated acreage will be developed by this customer does remain uncertain.
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 new contracts with other customers in this area and that we are beginning to see that our planning development activity in and around the LN system footprint.
And then finally in the northeast we're currently expecting 30% to 44, new well connects in 2022 and this is relative to approximately 50 wells in each of 2020 in 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.
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 and the Utica.
It's 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 the sale of this acreage could really become a significant catalysts 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.
Thanks, Steve 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, our 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.
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 start 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 124 Bcf per day during the quarter, which is inclusive of 530 million a day of 80 eights OTC volumes and.
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 our system, partially offset by 16, new wells brought online during the quarter.
All of which four were connected directly behind our wholly owned Utica system in November these.
Four wells IP that 100 million a day.
100 million a day.
Which was in line with our internal expectations and represented a another set of wells that IP north of 20 million a day behind our system.
The northeast segment currently has 15 docs, 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 benefit related to the settlement of a legal matter with a vendor in the third quarter.
Liquids volumes averaged 62000 barrels a day a decrease of 1000 barrel a day from 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 out wells that were connected behind our crude oil.
Late in the quarter.
The Rockies segment currently has 11 docks 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 <unk> in the double E pipeline reported adjusted EBITDA of $2 6 million, representing a $2 $1 million increase relative to third quarter.
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 <unk> volumes averaged 124 million a day on an age basis for the quarter, while online with slow beginning on November 18th.
No new wells were connected behind our JMP asset during the quarter, but as of year end, we had four docks bound our G&P system, which represent the only direct well connects we expect at this juncture for calendar year 'twenty two.
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 two very active private producers in the area, which had eight active new drill permits today.
We continue to discuss potential development plans for 2022 and beyond but but are encouraged by this acreage get in the hands of more active customers.
Lastly, we are encouraged to see M&A transactions like the <unk> deal getting done at multiples estimated at over 10 five times. 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 135 Bcf a day, we expect S. MLP, 70% interest in double E to generate approximately 45 million of EBITDA.
And as of yearend, we had $106 million of debt outstanding and $100 million of preferred equity outstanding at our unrestricted subsidiaries.
The <unk> segment reported adjusted EBITDA of $15 9 million down 3 million relative to third quarter due to $3 4 million of Nbc's that expired in the third quarter. This.
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 averaged 317 million a day, a slight increase relative to third quarter and there are no docks 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 all 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 late in late September .
Which increased volumes from 201 million a day to 222 million a day in the fourth quarter.
As Steve mentioned, these wells, where the best wells, we've ever seen on the system and are a direct result of the technological improvements producers are implementing into their DNC programs.
These wells IP, Ed 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 in LNG export market. We are excited about the prospects for additional development behind the system that the street is likely written off as a PDP decline asset.
There are currently four docks behind the system, which represent all the wells, we expect that 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 as MLP route.
<unk> 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, and our Utica Permian and Williston systems.
During the quarter, we also invested $6 million into summit Permian transmission, Holdco, which we will believe will satisfy the vast majority of vessel bolt piece remaining net investment in <unk> during 2022.
With respect to ask Mlp'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 cost of doubly 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 his 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 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 or 2021 outperformance was a result of our customers hitting their targets and thats MLP benefiting from a handful of tailwind that pushed us nearly 10% above the midpoint of our original guidance we.
We hope that we experienced similar tailwind 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 one time operating expenses related to certain asset integrity and regulatory initiatives. In addition, theres approximately $6 million of similar maintenance Capex expenditures included in our Capex range.
We believe these investments will better position as MLP drop 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're 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 Keith for closing remarks, alright. Thanks, Bill. So look again, while we're obviously disappointed with the limited activity there 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.
Admittedly, we anticipated that 2021 would be the trough year for summit and that the U shaped recovery would begin.
We moved into 2022 and that was particularly driven by fundamentals in 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 uncertainty that that could potentially lengthen the timeframe for that would allow us a U shaped recovery to occur for some of these 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 plans 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 will now begin the question and answer session.
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Please hold for a moment, while we assemble Archie.
From U S capital, we have James Carreker. Please go ahead.
Good morning, guys. Thanks for the call.
Just wondering does this latest outlook.
In a new way affect any.
Coverage covenants or leverage restrictions that might've been in place.
On the new debt financing that you completed last year.
Hey, James This is bill no we.
That was that was really a key consideration as we thought about the refinancing package and putting their covenant light package in place.
We really think about the covenant package really being limited to a.
The minimum interest coverage of two times and then a first lien.
First lien secured so think of that as the ABL.
Max leverage of two five times.
Based on this guidance range.
We expect to be in compliance with both of those throughout the course of 2022.
Gotcha, and then maybe just thinking.
Broadly alright.
And remembering right a lot of the systems were built with strong NBC protection, So I guess things.
Thinking about the decline.
Year over year.
How much of that is kind of nbc's rolling off how much of that is it's kind of.
Production declines is there any way to kind of bucket that yes, sure and then I guess you have.
Follow up to that is kind of.
What does the MVC roll off situation look like 'twenty three and beyond.
Yeah, No that's a great question.
I would point you to.
<unk> focus on that MVC shortfall payments section within our guidance, if you kind of track that over the over the quarters Youll notice in the Piceance, we had about a $3 $2 million decline from the third quarter or 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.
$13 million roughly declined 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.
<unk>.
And how we've been generally describing that is think of that as call it $10 million reductions over the over the next call it three or four years.
Until that.
<unk> expires I think our last <unk> in 2026.
That's helpful and then if I could maybe fit into another one just kind of curious.
Excuse me.
Just on the double E throughput outlook.
I guess just any commentary on maybe why that is.
Maybe like about half.
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 of 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, one and as a reminder.
That sculpt and increases such that by November of 2020 for those contracts will be fully ramped at one Bcf a day, which is the existing contracts.
So.
Producers, obviously, they expect to log in to those contracts.
That was part of your initial planning and Thats 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 the EBITDA to be around $45 million not to summit.
And just as a reminder, that when we talk about <unk> and the volumes I mean, these are virtually 100% take or pay type contracts. So so there's really very little revenue associated with just throughput. It's all based on demand charges and contracted capacity to build just walked you through.
Okay.
That's helpful.
I guess just one more.
I guess as you look forward.
You've obviously got the ramp of <unk>.
I guess what.
What area would you have the most optimism and in reinvigorating some level of growth as we look to 2023.
One early discussions are there with producers that would.
Indicate that.
We're really excited about the Utica.
Yes.
Right.
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 theres really not a well behind our system that would not be economic to drill obviously.
That's a lot of people will say that in the in the U S. Shale I mean that kind of certainly at that pricing level you get 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 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 X T O 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.
I'd say two out of the three have not been active in the past couple of years has since been driving most of the volumetric growth behind our systems, both the OTC system in our SMU system. So I think.
Look these wells are we've seen more well activity when prices were $2 50, and what we're seeing right now where prices are four.
<unk> hundred 50, plus so economically I think theres no doubt.
That if prices that people get comfortable and the fundamentals that hey, not just right now, but if you look out over the next three to four 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.
<unk>, we love them to death, they are important customers in three basins for us.
If they are successful monetizing that position I think someone stepping into that position and getting back to drilling can be very meaningful for years to come so I put Utica out there is probably.
Very high I would say the Williston.
We had 30 wells come online really since the September and the second half activity is very needed right now.
I'd say, we are private producers have kind of they're.
They're not doing anything heroic, but most of the wells that we're projecting for 2022 or from the private side. We've got a large customer that acquired brewin out of bankruptcy and I guess it was during the during or after bankruptcy anyway. After bank right after bankruptcy.
I would say.
That producer right now it's a public guy is just not active on our footprint they are drilling out there.
Berthold reservation acreage.
We'll see whether or not they continue to.
When they come back into our area, but we've got very expensive 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 two areas that I'd say.
I would I think we should see.
Well connects potentially double if not triple in this 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 of a sub 60 and gas was up $3.
Those are the two I'd say the other area that we're kind of as an anomaly is the D. J just given the economics.
As we said in the call virtually all of our Rocky segment, which is now <unk>.
Jay and the Bakken, but virtually all of the activity. We're projecting in 2022 is in the Bakken, which means we have maybe one or two wells in the D. J.
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 theyre highly economic to develop and we're hopeful I think EOG being a public guy and I'm sure. They are sophisticated enough not to just go out there and chase prices, but I think if the fundamental support it they certainly.
View this acreage to be highly economic.
We know that theyre going to get to it in time, but that 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 even.
Even the Barnett and the payoffs I mean, we're seeing activity.
Particularly in the Barnett just at these gas prices.
Fairly consistent activity now that may not grow production. 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.
<unk> 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 a call.
Call It a 10% PDP decline type assets.
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 would add up in the up in the Utica as Heath mentioned with with <unk>.
<unk> in that acreage position.
That was developed in a period of kind of the old school period, right where you.
Put down one or two 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 not to summit.
And very incremental to the free cash flow profile.
I.
I'll, let Colin thank you.
You bet.
Once again, if you do have a question. Please star one on your phone keypad.
And from Bank of America, we have Gregg Brody. Please go ahead.
Yes.
Hey, good morning, guys and thank you for all the details.
A lot of good questions asked there also.
This analyst.
Just I just wanted to touch base on a couple of follow ups. There. So I was just the Utica I appreciate the assets end up in different hands that can be developed I'm curious.
How do you how do you do about the takeaway capacity there.
Just out of basin or is there demand in basin.
Our core ramping gas.
I think the short answer we feel pretty comfortable that theres takeaway out of the basin. We also think of these elevated prices on a basis adjusted basis net to the wellhead theres still highly economic to drill.
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.
Companies must caf.
I mean, the short answer is I don't have a specific number that I can give you I think what it is.
What we've seen in the past as 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 the basis down, but I don't think we've ever been in.
Spot to where we physically had to shut in gas or was unable to move gas out of the question is at what price and the point being.
<unk>, we've seen two in a quarter, maybe even below two and a quarter on a basis standpoint.
Standpoint, and it still makes 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, that's really in our opinion gets down to kind of a we feel like it's somewhat of an anomaly year with the Utica just given what the what the what the returns would be for incremental wells that would that would come online.
Lynn.
We're hopeful that whether it's the CEO position whether it's.
Gulfport.
I'm starting to put some rigs to work or scent private guy up they're 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 <unk>.
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 just you talked about the Permian there've been a lot of activity there just for the.
For the potential.
Part of <unk> Thats, not contracted yeah, adding capacity, adding a contract do you have any line of sight as to how long that will take any of that.
Pits there that are relevant that this is something that could happen this year.
I think look.
I would say that if you look at new Mexico, and you look at the fact that they are really there.
This is the only new infrastructure that's been placed in service you look at the rigs.
Can easily start seeing in 2023, there being a problem getting gas out of new Mexico.
<unk> was obviously forward thinking on that and that's why <unk> was so strategic that they were our 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 semi gas at the wellhead and at times, maybe they lag a little bit until they see some price signal that suggests the need to have transport and we think that 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 will 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 I think by 2024. If this thesis continues to play out we continue to see rig activity and growing production.
Would be surprised if we weren't able to get the 135 fully subscribed here between.
Between now and 2024 could could ramp up a little bit.
That's yet to be determined, but it's hard for us to see that how that doesn't happen just given the trajectory of volumes and the other point is that we see.
Not only just that 135, but we've got a very inexpensive basically out of mainline compressor station on existing <unk> to be able to take that up to two 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 that compression up and down though that will require FERC.
Process and something that we're going to be as we talked 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 one the main pipeline in service.
Got it and then just just the.
In terms of I know the term loans term loans drawn there.
At doubly at the JV.
Just think about I.
I know you've talked it's pretty much just paying that down right. Now are there any plans to to trust the preferred or the turmoil in some way that that could.
Change the capital structure at all.
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 are 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 a fairly limited cash flow back to <unk>, but it's also very attractive capital attractively priced.
It's cash pay on the preferred at 7% and the bank deal down there the term loans at L. Plus 237, five so very very attractive pricing.
I think you would see us potentially look at recapping that once we get another decent sized long term contract.
And I think that's just an ongoing.
And have a SaaS man and again as this as double Lee is generating this free cash flow and distributions are paid to that chain.
It does.
You kind of outlined the 160 million outstanding at year end on the term loan and then $100 million.
On the <unk>, we're going to be pain, 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 asphalt paradigm.
That makes that makes sense. When you you touched on my next question. So you think there's a possibility you could take a dividend at some point.
That helps with that helps pay down preferred.
Could you talk a little bit about that 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.
Played that out or.
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 you can take all of that.
You would need some of that to fund down there right.
How much do you think.
Yeah.
How much are you, saying that that would be the incremental borrowing capacity.
With.
With that incremental contract. So a majority of that we'd be able to distribute up in service.
<unk>.
Got it and then.
And any other way.
So you are thinking about today to address that is the equity the equity exchange game still a tool that's been that's played out.
On the <unk> side, I think I think I think we like the capital structure, we've got in place.
I'm, referring to the preferred at summit Oh got it got it.
Look we've on the preferred we've done what three or four exchanges already.
Greg 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.
We want to stay there.
But the critical strategic point of that was getting that below a $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.
Maybe you could talk a little bit about you talked about maybe pruning some assets in the press release, you talk about how much you think that could be this year and then can you talk about.
We have an opportunity for you to.
Opportunity for you.
Sorry, I didn't catch the first your first.
You mentioned in the press release, you might prune some assets.
This year do you have a sense of how much that could be.
I think look I mean.
What I would say and 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 start we certainly have seen.
M&A pick up a bit when theres been a few deals that have gotten done.
If we see an opportunity an actual opportunity too.
Acquire or divest of an asset that we think makes sense and is done at a at an attractive value. We're going to 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.
I don't think its worth speculating I mean, we've got our our feelers out on a lot of stuff right now.
Who knows but we will certainly I just wanted to let you know at least the mindset of the management team and the board is.
If theres 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, Greg. So last year, we sold 8 million box roughly kind of a wait and inventory.
Think of that as just compressor compressors, we werent using in other kind of assets like that that were sitting in 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 cut off.
Optimize our inventory and latent inventory.
Great.
Is it from me guys. Thanks for your help.
Got it.
Thank you ladies and gentlemen. This concludes today's conference. Thank you for joining you may now disconnect.