Q2 2023 Summit Midstream Partners LP Earnings Call

Participants

J. Heath Deneke; President, CEO & Chairman of Summit Midstream GP, LLC; Summit Midstream Partners, LP

Randall Burton; Director of Finance, Treasurer & IR; Summit Midstream Partners, LP

William J. Mault; Executive VP & CFO of Summit Midstream GP, LLC; Summit Midstream Partners, LP

Gregg William Brody; MD; BofA Securities, Research Division

Presentation

Operator

Good day, and thank you for standing by, and welcome to the Q2 2023 Summit Midstream Partners LP Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. I would now like to introduce your host for today's call, Randall Burton. Please go ahead.

Randall Burton

Thanks, operator, and good morning, everyone. If you don't already have a copy of earnings release, please visit our website at www.summitmidstream.com, where you'll find it on the homepage, Events and Presentations section or 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 Mault, our Chief Financial Officer; along with other members of our senior management team.
Before we start, I'd like to remind you that our discussion today may contain forward-looking statements. These statements may include, but are not limited to, our estimates of future volumes, operating expenses and capital expenditures. 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 1, 2023, 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, 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.

J. Heath Deneke

Thank you, Randall, and good morning, everyone. Summit reported second quarter adjusted EBITDA of $58.6 million, which was below management expectations primarily due to temporary shut-ins and deferrals of new wells behind our Barnett system, timing delays associated with well completions in the Northeast and Rockies 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 segment results later on in his commentary, but I did want to share kind of 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, 1 of our producers that turned 40 wells in line during the second quarter, subsequently shut in roughly $25 million a day of flowing production about 2 weeks later, which happened to more than offset the reduction from the new wells. We believe the shut-ins of these PDP wells was primarily driven by low summer gas prices relative to higher strip prices that are projected for late 2023 and during 2024. This appears to be an anomaly for the Barnett versus a trend and that we haven't experienced any economic-driven shut-ins by other Barnett customers or in any of our other operating segments for that matter. While timing is uncertain, we would expect that production from these shutting wells in the Barnett will come back online as gas price strengthens later this year and into next year.
Moving on to the Northeast. We connected 26 new wells during the quarter, which resulted in 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 slated to be turned in line in May were delayed into the third quarter.
In the Rockies segments, we fell behind quarterly expectations primarily due to roughly 30 well completions that slipped into the second half of 2023. So the aggregate, we connected just under 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 it certainly is the primary driver behind the second quarter miss.
The good news, however, is we've already connected an additional 45 wells over the past few weeks, including 28 in the Bakken and 17 in the Utica. And furthermore, based on recent customer plans, we still do expect to connect 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, it just has been delayed in terms of the timing throughout the year.
So as of today, we've connected 195 wells to the system thus far. We have 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 into 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 million to $85 million, respectively. These quarterly ranges generally reflect our latest producer turn-in-line dates on new wells that are expected for the remainder of the year on the high side. And on the low side reflects a further risk view of a continued slippage in timing of remaining wells along the lines of what we experienced during the first half of the year. It also includes our updated commodity price adjustments and risking on our POP 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. While we're certainly disappointed in the Q2 results and the associated 2020 calendar year impacts, we do believe largely that what we are experiencing is just a quarter or 2 overall delay in ramping up to the $300 million of LTM adjusted EBITDA that we expected to incur in 2023.
If you combine our updated third and fourth quarter outlook, along with the latest cadence of risk customer activity (inaudible) wells that are scheduled to turn online in the first half of 2024, we now expect to trend towards the $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 the segment results and expectations.

William J. Mault

Thanks, Heath, and good morning, everyone. 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 1,410 million cubic feet a day during the quarter, which is inclusive of 781 million cubic feet a day of 8/8ths OGC 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 OGC joint venture and 7 new wells behind our Mountaineer system during the quarter. While a majority of the frac protect related shut-ins we experienced at OGC in the first quarter were brought back online, there were still 35 million cubic feet a day of frac protect related shut-ins at SMU. Which we estimate impacted adjusted EBITDA by approximately $0.8 million.
The frac protect related shut-ins at SMU were offline longer than we expected given the delay in completion timing from the second quarter to the third quarter. With that being said, subsequent to quarter end, we brought on 9 new wells behind the SMU system with initial production rates that are beating our type curves, along with the $30 million of previously shut-in volume. We also had 8 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 3 rigs running behind the systems with 16 DUCs. 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 the 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 $0.80 per gallon in the first quarter down to approximately $0.60 per gallon in the second. Realized natural gas prices declined from approximately $4 per MMBtu in the first quarter down to approximately $1.60 per MMBtu in the second quarter. And WTI 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 in our original expectations, second quarter gas and NGL index prices dropped 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 and expect commodity prices to be back in line with our original expectations by the fourth quarter.
In the Williston, liquids volume throughput averaged 71,000 barrels per day during the second quarter a 4% decrease relative to the first quarter as a result of PDP declines and only 6 new wells coming online during the quarter.
As Heath mentioned, the 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. Again, while we are frustrated with the completion delays, activity levels remain robust. with 28 Williston wells connected in July at 6 rigs running, including 4 in the DJ and 2 in the Williston and more than 120 DUCs 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 $0.3 million relative to the first quarter. Piceance segment reported adjusted EBITDA of $14.4 million, an increase of $0.4 million relative to the first quarter, with volumes averaging 297 million cubic feet per day an increase of 3.5% relative to the first quarter, which was primarily due to volume from 15 new wells that turned in line during the quarter. There is currently 1 rig running, 24 DUCs 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 $0.2 million relative to the first quarter, primarily due to $1.8 million of other revenue and income, offset by an 8.5% decline in volume. During the quarter, a customer shut 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 shut-ins impacted adjusted EBITDA by approximately $1.8 million during the quarter.
Additionally, 1 of our customers decided to increase the number of wells being drilled on an existing pad site from 5 to 11. While this is certainly a positive development, this extended the drilling and completion timing into 2024. We currently expect 10 wells to be brought online and expect to have over 20 DUCs by the end of the year. There is currently 1 rig running and 24 DUCs behind the system today.
Quickly on the partnership. SMLP reported a second quarter net loss of $13.5 million and adjusted EBITDA of $58.6 million. As Heath mentioned, the adjusted EBITDA of $58.6 million was below our expectations and really can be boiled down to 3 main factors. First, we saw a shift in completion activity in the Rockies and Northeast segments that we estimate posted approximately $9 million of adjusted EBITDA from the second quarter into the 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 expenditures totaled $15.7 million for the quarter, in line with expectations and included $2.1 million of maintenance CapEx. The 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 SMLP'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 guidance at the segment level.
Starting in the Barnett, we originally estimated 25 to 30 well connections for 2023 and now only expect 10. The good news is that gas prices are expected to increase, and there'll be over 20 wells in DUC inventory by the end of the year with at least 11 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 7 to 8 months this year. Of the $15 million revision in this segment at the midpoint, roughly half was due to timing delays and the other half was due to unexpected shut-ins.
In the Rockies, total well connections are expected to generally remain in line with our original guidance. However, completions have shifted 1 to 2 quarters. In the DJ, commodity prices in the second quarter and what we expect in the third quarter are well below our original expectations, where 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 shift. In the Northeast, total well connections are also expected to remain in line with our original guidance, but 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.

J. Heath Deneke

Thank you, Bill. So to wrap up before we open up the call for questions, again, I wanted to acknowledge that our Q2 results and the reduction in calendar year adjusted EBITDA guidance is disappointing. We're 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 and as they have been in the past.
While we could see additional slippage relative to our customer plans on the remaining wells, which are explained to come online in Q3 and Q4 this year. We do believe that we have appropriately reached those potential delays within our updated third and fourth quarter outlook as well as our risk around our commodity price impacts on our POP contracts.
So big picture, as we look forward, I think there's a lot to be excited about at Summit, The vast majority of the 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, particularly in the Utica, our well performance expectations.
We continue to be very encouraged by the large inventory of drilling on complete wells and 11 rigs that are currently running behind our systems. And again, while we certainly acknowledge we're a quarter or 2 behind from what we originally thought, we still believe we are very well positioned to achieve $300 million of adjusted LTM EBITDA during the first half of next year.
So 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. And with that, operator, let's open up the call for questions.

Question and Answer Session

Operator

(Operator Instructions) Our first question comes from Gregg Brody from Bank of America.

Gregg William Brody

Thank you for all the details on 3Q and 4Q. 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 the hot weather across the country, has that caused any issues with operations this quarter or something we should be thinking about?

J. Heath Deneke

This is Heath. No, we really haven't. And truthfully, outside of the Barnett, honestly, even the lower pricing really didn't -- may have had some slippage around some of the drill connect -- some of the well connects that we scheduled or thought would come online in Q2 but it really hasn't changed the producer activity levels, both from a completion standpoint or a 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 returned online. And I suspect that might be a little bit of commodity driven, (inaudible) month versus this month. But for the most part, our activity levels have remained pretty resilient.

Gregg William Brody

Got it. And then just to shift to Double E, I think -- I'm trying to think about how you're thinking about the ramp there from this point? Maybe you can just give us an idea how to think about that? And within that question, based on what you look at today, I think the longer-term plan is to fold that into the restricted group. How -- where do you see timing on that today?

J. Heath Deneke

Yes. Yes. Timing is a little hard to predict, but we -- the fundamentals are just continuing to strengthen out there. We know that -- there's a lot of new plants that have been announced and they're getting constructed right alongside the Double E 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 has already stepped up already, right?

William J. Mault

Yes, Gregg. So as we see it, where kind of Eddy and Lee County production sits today, you're right around that kind of a wellhead, 2.7, 2.8 Bcf, we think that's 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 a 200 million 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, but the New Mexico side stayed pretty resilient at 100 to 110 rigs running.

J. Heath Deneke

Yes. So a long way of saying, it's kind of tough to give you like a specific certainly in talks. We have been in talks with producers. We are seeing the need for incremental capacity as these new plants come online. So there's no doubt about that. The question is the timing of when we'll secure new contracts and the timing of when those volumes or the contract volumes will start. I would tell you that just looking at the level of increase in gas in New Mexico and kind of that Loving, Reeves County area, if you kind of follow that trajectory, we think certainly over the next year or 2, we should see some EBITDA ramp-up and some contracts get announced. .

Gregg William Brody

And there's been some M&A up there. Do you think -- it seems like the M&A has been -- companies buy the assets and then they cut the rig count relative to where the other company was operating them. Have you seen that anywhere on your footprint that's notable?

J. Heath Deneke

Not really, honestly, we -- you see that much more in the Midland. I think we certainly have seen some consolidation. But in and around our footprint, the producers, obviously, Exxon being our anchor customer. You've got a lot of New Mexico private guys like the Mewbournes of the world, they're 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's interesting about this is as 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 Waha. So there's a little bit of a timing gap here that getting to Waha 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.

Gregg William Brody

When you say the downstream you're referring to the long-haul pipeline. Is it correct.

J. Heath Deneke

That's correct.

Gregg William Brody

And just as this question leads to my next one. Just how are you thinking about sort of the refi today of your capital structure and what's the current thoughts?

William J. Mault

Yes. Gregg, it's Bill. So look, we've got $260 million kind of unsecured that 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, 1 being potentially kind of full recapitalization of the second lien on the unsecured an option of just doing maybe a stub 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, Gregg, I think about it as we've got some great momentum here coming in the second half. We want to start proving 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 just cadence of when we'll come out with additional information, in February next year, we'll 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, Gregg, for us to -- once we get all that information out to the market to then go execute on a refinancing.

Gregg William Brody

That makes sense. And then just I think part of that strategy historically has been M&A potentially to deleverage. Can you talk about the opportunity set out there today. And as -- is that something that you're working on?

J. Heath Deneke

Yes. I mean look, honestly, we're kind of focused just with the growth ahead of us on our existing footprint. I think that's been the primary focus. We certainly have -- continue to see a theme of 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 we're -- we just have so much momentum here operationally. It has to be the right deal and the right deal, again, is meaningfully credit accretive something that we can kind of get tucked in with good operating synergies that really makes a lot of sense with our footprint.

Gregg William Brody

Is there -- I appreciate the focus is on growth, is there's I guess, are there still -- are there a fair amount of opportunities out there? Or it's just...

J. Heath Deneke

Yes, definitely good opportunity sets. And I think that what we're emphasizing is we're pretty comfortable with the portfolio that we have now. And so we'll be opportunistic if something that 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 time will tell.

William J. Mault

Yes. And Gregg, just to provide a little color to in the DJ in particular, there's probably 5 smaller kind of sponsor-owned type assets that are strategic to our business. Now how strategic kind of range is. Some are highly strategic, some are modestly strategic, that we'll keep an eye on. And then to Heath's point, up in the Williston, there's a couple of things that are really interesting to us, but we'll 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 want to make sure we're kind of hitting that -- hitting our numbers and hitting that growth.

Gregg William Brody

I appreciate that. And maybe the last 1 here. So there's still a small piece of the preferred out there. Is that something that you're -- you just have to be working on that? And just if the opportunity is there, you'll address it? Or is that something that is on hold?

William J. Mault

Yes, Gregg, I mean it's not a huge chunk of the capital structure. It's perpetual. We can continue to kind of accrued distributions there. I think where you'll see us maybe more actively think about alternatives on that piece of paper is when we're ready to turn on kind of a common distribution. And we've got some wood to top 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 kind of total leverage.

Operator

And I am showing no further questions. This concludes today's conference call. Thank you for participating. You may now disconnect.