Q2 2023 Summit Midstream Partners LP Earnings Call
Good day, and thank you for standing by and welcome to the Q2 2023 summit Midstream Partners LP earnings Conference call. At this time, all participants are in a listen only mode.
Speaker's presentation there'll be a question and answer session to ask a question. During the session you will need to press star one on your telephone you then here in the automated message advising your hand is raised to withdraw your question. Please press star one again, please be advised that today's conference is being recorded.
Now I'd like to introduce your host for today's call round. The Burton. Please go ahead.
Thanks, operator, and good morning, everyone if.
If you don't already have a copy of our earnings release. Please visit our website at Www Dot summit midstream Dot com, where you'll find it on the homepage events and presentations section of our quarterly results section.
With me today to discuss our second quarter of 2023 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. They may also include statements concerning anticipated cash flow liquidity business strategy and other plans and objectives for future operations.
Although we believe that these 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 2022 annual report on Form 10-K, which was filed with the SEC on March one 2023, as well as our other SEC filings for a listing of factors that could cause <unk>.
<unk> results to differ materially from expected results. Please also note that on this call. We use the terms EBITDA adjusted EBITDA distributable cash flow and free cash flow. These are non-GAAP financial measures.
And we have 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.
Hey, Thank you Randall and good morning, everyone Summit reported second quarter adjusted EBITDA.
$8 6 million, which was growing management expectations.
Merrily due to a temporary shut ins and deferrals of new wells behind our Barnett system timing delays associated with well completions in the northeast and rocky regions and lower than expected commodity price impacts.
Despite these headlines summit still had a very active quarter, we connected a total of 89 wells during the quarter across our operating segments.
Bill will get into much further detail on our segment results later on in his commentary, but I did want to share a few comments on a few key points for the quarter before we start looking ahead to the second half of the year.
So starting in the Barnett one of our producers.
Turning 40 wells in line during the second quarter subsequently shut in roughly 25 90 day of LOE and production about two weeks later, which more than offset the production from the new wells.
We believe the shut ins at least PDP wells was primarily driven by low summer gas prices relative to higher strip prices that are projected for late 2023 and during 2024.
While timing is uncertain, we would expect a production from the shut in wells in the Barnett will come back online as gas prices strengthen.
For this year and into next year.
Moving on to the northeast, we conducted 26, new wells during the quarter, which resulted in a quarter over quarter segment adjusted EBITDA growth of 13%.
This is a really nice pickup. However, we did have roughly 20 wells, none of which were big wells behind our wholly owned SMU system, which were ready to be turned in line in may were delayed into the third quarter.
And Iraqi segments, we fell short of expectations, primarily due to roughly 30, well completions that slipped into the second half of 2023.
So in the aggregate we collected just under a 150 wells in the first half of the year, which compares to roughly 200 wells that we had originally planned to connect during that time.
So that's the bad news and there certainly is the primary driver behind the second quarter Miss.
The good news. However is we've already conducted an additional 45 wells over the past few weeks, including 28 in the Bakken and 17 in the Utica.
Furthermore, based on recent customer plans, we still do expect to conduct a total of 300, new wells to the system by the end of the year, which again is generally in line with our original expectations.
This has been delayed in terms of the timing throughout the year.
So as of today, we connected 195 wells to the system thus far.
Over 180 drilled but uncompleted wells in inventory and we continue to have 11 active rigs running behind our system.
This is a strong and encouraging level of activity from our customer base, which is fueling our confidence that we will continue to drive meaningful sequential quarterly growth beginning in the third quarter and as we look ahead to 2024.
So looking ahead as announced in our press release last night, we now expect our third and fourth quarter adjusted EBITDA to range from $65 million to $75 million and 75% to $85 million respectively.
These quarterly rate is generally reflect our latest producer turn in line dates on new wells that are expected for the remainder of the year.
And on the LOE side reflects a further risk view of it.
Continued slippage in timing of remaining wells.
Kind of what we experienced during the first half of the year.
It also includes our updated commodity price adjustments and risking on a PLP contracts.
So based on the first half of 2023 actual results and the updated second half of 2023 quarterly outlook. We're revising our 2023, adjusted EBITDA guidance to $260 million to $280 million.
Well, we're certainly disappointed in the Q2 results and associated 2020 calendar impacts and we do believe largely that what we are experiencing is just a quarter or two overall delay in ramping up to the 300 million LTM adjusted EBITDA that we expected to occur in 2023.
If you combine our updated third and fourth quarter outlook, along with the latest cadence at risk customer activity and care every wells that are scheduled return online in the first half of 2024.
We now expect to trend towards that $300 million of adjusted EBITDA.
During the first half of 2024.
So with that let me turn the call over to Bill to provide some additional color on our segment results and expectations.
Thanks, Keith and good morning to everyone in the northeast, which is inclusive of our SMU system proportionate share of our Ohio gathering joint venture and our Marcellus system. This segment averaged 1000 410 million cubic feet a day during the quarter, which is inclusive of $781 million.
Cubic feet, a day of 80 eights OTC volumes.
Segment, adjusted EBITDA totaled $20 2 million, an increase of $2 3 million, representing 13% growth relative to the first quarter, primarily due to an increase in volumes.
Two new wells were brought online behind our wholly owned SMU system 17, new wells behind our OTC joint venture and seven new wells behind our mountaineer system during the quarter.
While the majority of the Frac protect related shut ins, we experienced at OTC in the first quarter were brought back online there were still 35 million cubic feet a day of Frac protract related shut ins at SMU.
Which we estimate impacted adjusted EBITDA by approximately.
Zero point $8 million.
The frac protect related shut ins at SMU or offline longer than we expected given the delay in completion timing from the second quarter to third quarter.
With that being said subsequent to quarter end, we brought on nine new wells behind asking me system with initial production rates that are beating our type curves.
Along with the $30 million previously shut in volume.
We also had eight new wells subsequently connected behind our Ohio gathering joint venture.
Although delayed we remain very excited about the well results and activity levels, which we expect to continue to drive significant volume and segment adjusted EBITDA growth in the second half of the year.
There are currently three rigs running behind our systems with 16 docks.
The Rockies segment, which is inclusive of our DJ and Williston Basin systems generated adjusted EBITDA of $16 9 million a decrease of $6 3 million from the first quarter, primarily due to lower volumes and lower realized commodity prices.
Fixed fee oriented revenue decreased approximately $3 2 million, primarily due to lower volumes and customer margin mix and commodity based margin decreased $2 7 million due to a combination of lower volumes and lower commodity prices.
In the DJ natural gas volume throughput averaged 99 million cubic feet per day, representing an 8% decline relative to the first quarter.
While there were 38, new DJ wells connected in quarter. These wells didn't materially contribute to volumes in the second quarter.
And as a reminder, given the natural gas type curves in this area. We would expect these 38 wells to achieve peak production in the fourth quarter of this year.
To provide a little context on commodity prices realized composite NGL prices declined from approximately 80 <unk> per gallon in the first quarter down to approximately 60 <unk> per gallon in the second.
Realized natural gas prices declined from approximately $4 per <unk> in the first quarter down to approximately $1 60 per annum btu in the second quarter.
<unk> prices, which impacts our condensate sales in the region declined from $75 per barrel to approximately $70 per barrel.
While we projected declines in commodity prices and our original expectations second quarter gas and NGL index prices drop much lower than what was anticipated in the general marketplace and ended up 25% to 35% below our original guidance assumptions during the quarter.
Based on current strip pricing, we believe that second quarter will represent the trough in commodity prices for the year.
Commodity prices to be back in line with our original expectations by the fourth quarter.
In the Williston liquids volume throughput averaged 71000 barrels per day during the second quarter.
4% decrease relative to the first quarter as a result of PDP declines and only six new wells coming online during the quarter.
As Steve mentioned, a number of well connections was well below our expectations in the quarter and was primarily due to a shift in completion timing from the second quarter to the second half of the year.
While we are frustrated with the completion delays activity levels remain robust with 28 Williston wells connected in July .
Six rigs running including four in the DJ and two in the Williston and more than 120 docks behind the systems.
The Permian Basin segment, which includes our 70% interest in the double E pipeline reported adjusted EBITDA of $5 4 million, an increase of <unk> 3 million relative to the first quarter.
<unk> segment reported adjusted EBITDA of $14 4 million, an increase of <unk> 4 million relative to the first quarter with volumes, averaging 297 million cubic feet per day, an increase of three 5% relative to the first quarter, which was primarily due to volume from 15, new <unk>.
That turned in line during the quarter.
There is currently one rig running 24 docks and we continue to expect 55 total wells to be connected to the system in 2023.
The Barnett segment reported adjusted EBITDA of $7 3 million, an increase of <unk> $2 million relative to the first quarter, primarily due to $1 8 million of other revenue and income.
Offset by an eight 5% decline in volume.
During the quarter, our customers shutting in approximately 25 million cubic feet per day of production due to low natural gas prices and we continue to have approximately 5 million cubic feet a day shut in for Frac protect activities.
We estimate that the 25 million cubic feet per day of unexpected shut ins and 5 million cubic feet a day of expected frac protect sharon's impacted adjusted EBITDA by approximately $1 8 million during the quarter.
Additionally, one of our customers decided to increase the number of wells being drilled on an existing pad site from five to 11.
While this is certainly a positive development has extended the drilling and completion timing in the 2024.
We currently expect 10 wells to be brought online and expect to have over $20 by the end of the year.
There is currently one rig running in 24 docks behind the system today.
Quickly on the partnership MLP reported a second quarter net loss of $13 5 million and adjusted EBITDA of $58 6 million as Heath mentioned, the adjusted EBITDA of $58 six was below our expectations and really can be boiled down to three main factors.
First we saw a shift in completion activity in the Rockies and northeast segments that we estimate pushed approximately $9 million of adjusted EBITDA from the second quarter into third quarter.
Secondly, there was approximately $2 million of lower than expected realized commodity prices in the DJ which should start trending upward in the third and fourth quarters.
And approximately $1 5 million of unexpected economic shut ins in the Barnett.
While this impacted results relative to our internal expectations in the second quarter is providing confidence in our expectation to generate $65 million to $75 million of adjusted EBITDA in the third quarter.
Capital.
<unk> totaled $15 7 million for the quarter in line with expectations and included $2 1 million of maintenance Capex.
Majority of the Capex spent during the quarter was in the Rockies and associated with pad connect costs and DJ basin integration projects.
With respect to ask Mlp's balance sheet, we had net debt of approximately $1 36 billion and total liquidity at the end of the second quarter totaled approximately $80 million.
Before turning the call back to Heath I'd like to break down the 35 million or 11, 5% reduction at the midpoint of our revised 2023 adjusted EBITDA.
<unk> guidance at the segment level.
Starting in the Barnett, we originally estimated 25 to 30, well connections for 2023 and not only expect 10.
The good news is that gas prices are expected to increase and there will be over 20 wells in DUC inventory by the end of the year.
We are at least 11 is scheduled to be turned in line by our anchor customer during the first half.
The other major impact was the 25 million cubic feet a day of unexpected shut ins that we expect for seven to eight months this year.
Of the $15 million revision in this segment at the midpoint.
<unk> half was due to timing delays and the other half was due to unexpected shutdowns.
In the Rockies total well connections are expected to generally remain in line with our original guidance. However, completions have shifted one to two quarters.
In the DJ commodity prices in the second quarter and what we expect in the third quarter are well below our original expectations, while we expect prices to catch back up to our original expectations in the fourth quarter.
Of the $15 million impact in the Rockies segment $10 million is due to timing shifts and approximately $5 million is due to commodity price chef.
In the northeast total well connections are also expected to remain in line with our original guidance that completions have shifted by approximately a quarter.
We estimate that that shift, which was partially offset by higher than expected initial production rates, thus far in the third quarter impacts our expectations by approximately $5 million.
And with that I'll turn the call back over to Heath for closing remarks.
Thank you Bill so to wrap up before we open up the call for questions again wanted to acknowledge that our Q2 results in a reduction in calendar year adjusted EBITDA guidance is disappointing.
We are admittedly frustrated with the extent of the delays in well completion dates that shifted largely from Q2 into the second half of the year.
And related these shifts were not communicated to us as timely as they had been in the past.
While we could see additional slippage relative to our customer plans on our remaining wells, which are slated to come online in Q3 and Q4. This year. We do believe that we have appropriately risk those potential delays within our updated third and fourth quarter outlook as well as our risk around our commodity price impacts on a PLP contracts.
So big picture as we look forward I think there is a lot to be excited about it Sean.
Majority of that Q2 wells that were delayed in the Rockies and northeast segments have been turned online already.
And we continue.
To see those wells performing either within or certainly in some cases exceeding and particularly in the Utica are well, our well performance expectations.
And we continue to be very encouraged by.
By the large inventory of drilled Uncomplete wells and 11 rigs that are currently running behind our systems and again, while we certainly knowledge, we are a quarter or two behind from what we originally thought we still believe we're very well positioned to achieve $300 million of adjusted LTM EBITDA during the first half of next year.
And we look forward to providing further updates as we progress throughout the year I'd like to thank you for your time and continued support.
Operator, let's open up the call for questions.
And thank you.
As a reminder to ask a question. Please press star one on your telephone and wait for your name to be announced to withdraw your question. Please press star one again.
Please standby, while we compile the Q&A roster.
And again that is star one one.
And one moment for our first question.
First question comes from Gregg Brody from Bank of America. Your line is now open.
Hey, good morning, guys. Thank you for all the details on.
<unk> and <unk>.
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Just just to add to that you mentioned, obviously commodities have improved so it's easier to.
See the visibility of drilling here.
Have you seen any issues with with the hot weather.
Across the country has that caused any issues with operations this quarter, something we should be thinking about.
Hey, Good morning, Greg Hi, This is heath.
We haven't.
And truthfully outside of the Barnett honestly, the even the lower pricing really didnt.
May have had some slippage around some of the drill.
Some of the well can actually schedule their adult would come online in Q2, but it really hasn't changed.
The producer activity levels, both from a completion standpoint or drilling standpoint, so I don't I really don't think it's weather I mean, there could have been cases, where we saw the wells were actually drilled and completed and still had almost a month before they are turned online and I suspect that might be a little bit of commodity driven painless way to mine and catch in IP next.
Versus this month, but for the most part our activity levels have remained pretty resilient.
Got it and then just shifting to <unk>.
I think.
I'm trying to think about how youre thinking about the ramp there.
Yes.
From this point.
Maybe you can just give us some idea of how to think about that and within that question based on what you've said today I think the longer term plan is to fold that into the restricted group.
Where do you see timing on that.
Today, Yes, yes timing is a little hard to predict but.
<unk>.
The fundamentals there.
Continuing to strengthen out there we know that there is a lot of new plants that have been announced and theyre getting constructed.
Right alongside the <unk> footprint. So we still feel very confident that we're going to fill up that.
The pipeline right now we've got about a Bcf a day contracted bill I believe the ramp is.
Yes, and stepped up already right, yes, Craig so.
No.
As we see it we're kind of adient Lea County production sits today.
You are right around that kind of wellhead.
Two point Sharon two eight Bcf, we think thats, a pretty important milestone where volumes kind of north of that should start to migrate towards the pipe.
And as Heath mentioned, we saw.
You may have noticed Matador announced.
Interest in expanding the former lane plant that we sold to them putting in 200 million very cryo there that's already connected to the pipe. Obviously so these are all good fundamental indicators.
And.
Look we've seen some rig reductions on the Midland side by the New Mexico side stayed pretty resilient.
100 to 100 110 rigs running.
So long way of saying, it's kind of tough to give you like a specific.
Certainly in talks we had been in talks with producers we are seeing the need for incremental capacity as these new plants come online. So theres no doubt about that the question is the timing of when we will secure new contracts and the timing of when those volumes are contract volumes will start I would tell you that just looking at the level of increase.
<unk> and gas.
In Mexico and kind of that.
<unk> Reeves County area.
If you kind of followed that trajectory, we think certainly over the next year or two we should see some some EBITDA ramp up in some contracts.
Get announced.
And then theres been some M&A up there.
Thanks.
Seems like the M&A has been.
Companies buy the assets and they cut the rig count.
Relative to what.
The other company was operating and then have you seen that anywhere on your footprint. That's notable.
Not really honestly.
You see that much more in the Midland and I think we certainly have seen some consolidation, but in and around our footprint that producers obviously are coming right.
Anchor customer you've got a lot of new Mexico private guys like the <unk> of the world.
Theyre still blowing and going and really up and down the footprint. We're just seeing quite the same kind of customer mix that we've been talking to for some time and I think what what's interesting about this is you kind of look out over time, we're still kind of a little bit in between having all the downstream takeaway projects in service out of Wahoo.
So theres a little bit of a timing gap here that getting the white hot today, probably isn't as attractive once those pipelines come on so there's a little bit of that that we think is influencing the timing of us securing new incremental contracts.
When you say that youre, referring to the long haul pipelines.
Correct that's correct.
That's correct.
And just just does that question leads to my next one just.
How are you thinking about.
The refi today.
For your capital structure.
What's your what's the current thoughts.
Yes.
Hey, Greg It's bill.
So look we've got $260 million kind of unsecured debt comes due in April of 25. So we're certainly getting kind of close to that 12 month window, where we'd like to execute.
Look we're looking at a range of alternatives here.
One being potentially our kind of full recapitalization of second lien in the unsecured.
An option of just doing maybe.
A piece of paper to kind of extend out that $260 million unsecured.
And just do a little mini deal sometime next year, but I think from a cadence perspective, Greg.
Think about it as well.
We've got some great momentum here coming in the second half we want to start proven to the market that this growth is coming and then we've got real good line of sight to kind of that $300 million of LTM EBITDA.
And then as you think about.
No just cadence of when we will come out with additional information in February next year will be we'll put out our 10-K with calendar year results and come out with our formal guidance at that time, and I think that would be a pretty good time drag for us.
Once we get all of that information out to the market to then go execute on a refinancing.
That makes sense and then just.
Part of that strategy is typically has been.
M&A potentially to deleverage could you talk about the opportunity set out there today.
Is that something that youre working on.
Yes.
Honestly, we're kind of focused just with the growth ahead of us on our existing footprint I think thats been the primary focus we certainly have continued to see ethane consolidation opportunities in and around our footprint, particularly in the Bakken and the DJ area. So we're certainly evaluating those opportunities.
But it's not the primary focus right now I think where we just have so much momentum here operationally.
Has to be the right deal and the right deal again as you know.
Meaningfully credit accretive and jumping that we can kind of get tucked in with good operating synergies that really makes a lot of sense with our footprint.
Is there I appreciate the focus is on growth is there.
Alright.
I guess are there still are there a fair amount of opportunities out there or is it just yes.
Yes, that's definitely good opportunity sets and I think that what we're emphasizing as we're pretty comfortable with the portfolio that we have now and so we'll be opportunistic if something that they just really makes a lot of sense and we get it at the right value.
And there are some of those assets out there that we believe probably will transact over the next year or so, but whether or not that's post refinancing or in conjunction with refinancing yeah. Tom will tell yes, and Greg just to provide a little color too.
The DJ in particular, there's probably five smaller kind of sponsor owned type assets that are strategic to our business now.
Our strategic kind of ranges some are highly strategic some are modestly strategic.
That will keep it keep an eye on and then to.
He's point.
Up in the Williston Theres, a couple of things that are really interesting to us.
But we will continue to be patient around those opportunities and again.
We kind of knew coming into this year that it was going to be a huge execution year with what we've got in the portfolio today.
So we'd want to make sure we're kind of hitting that.
Hitting our numbers and hitting that growth.
I appreciate that.
And maybe the last one here.
It's still a small piece of the preferred out there is that something that you just absolutely working on that and just the opportunities there.
Yes, it or is that something on.
On hardware.
Yes, Greg I mean, it's.
It's not a huge chunk of the capital structure, it's perpetual.
We can continue to kind of.
Crude distributions, there I think where you'll see us maybe more actively think about alternatives on that piece of papers when we're ready to turn on kind of a common distribution and we've got some wood to chop to get to kind of our leverage target. So it's not a huge focal point for us at the time being.
We are cognizant that it continues to accrue, but really our focus is on really driving this EBITDA growth and driving down our cost.
Our total leverage.
I appreciate the time guys.
Thank you Eric.
And thank you.
And I am showing no further questions. This concludes today's conference call. Thank you for participating you may now disconnect.
Okay.
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Okay.
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