Summit Midstream Corporation

Good day, and thank you for standing by, and welcome to the Q2 2023 Summit Midstream Partners LP earnings conference call. At this time, our participants are in listen-only mode. After the speaker's presentation, there'll be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. 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. Thanks, operator, and good morning, everyone.

If you don't already have a copy of our earnings release, please visit our website at www.summitmidstream.com, where you'll find it on the homepage, events and presentation 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 Moult, 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 reconciliation 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. Sherman reported second quarter adjusted EBITDA of 58.6 million, which was below management expectations primarily due to temporary shut-ins and deferral of the 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 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, one of our producers that turned four new wells in line during the second quarter subsequently shut in roughly 25 million a day of flowing production about two weeks later, which happened to more than offset the production 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 in 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 shut-in wells in the Barnett will come back online as gas price strengthen 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 EBDA growth of 13%. This is a really nice pickup. However, we did have roughly 20 wells, nine 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 rocky segments, we filled on quarterly expectations primarily due to roughly 30 well completions that slipped into the second half of 2023. So in 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. 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 incomplete 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 to 75 million and 75 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 to $280 million. While we're certainly disappointed in the Q2 results and the associated 2023 calendar impacts, we do believe largely that what we are experiencing is just a quarter or two overall delay in ramping up to the $300 million of 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 of risk customer activity and caregiver wells that are scheduled to turn online in the first half of 2024, You know, we now expect a 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.

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 8H 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 seven 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 Fract 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 nine 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 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 to EBITDA growth in the second half of the year. There are currently three rigs running behind the systems with 16 ducts. The rocky 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 80 cents per gallon in the first quarter down to approximately 60 cents 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 WDI 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 six 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, 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 EE pipeline, reported adjusted EBITDA of $5.4 million, an increase of $0.3 million relative to the first quarter. Peon 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's currently one rig running, 24 ducts, 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 Fract 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 Fract Protect shut-ins 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 5 to 11. While this is certainly a positive development, it has extended the drilling and completion timing into 2024. We currently expect 10 wells to be brought online and expect to have over 20 docks by the end of the year. There is currently one rig running and 24 docks 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 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 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, it is providing confidence in our expectation to generate 65 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 PadConnect 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 the gas prices are expected to increase and there'll be over 20 wells in duct 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 seven to eight 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 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, but we expect prices to catch back up to our original expectations in the fourth quarter. Of the $15 million impact in the Rocky segment, $10 million is due to timing shifts and approximately $5 million is due to commodity price shifts. 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.

Thank you, Bill. So to wrap up before we open up the call for questions, I again 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 really that 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 slated to come online in Q3 and Q4 this year, we do believe that we have appropriately risked 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 Utica, our well performance expectations. We continue to be very encouraged by the large inventory of drill bin uncomplete wells and 11 rigs that are currently running behind our systems. And again, while we certainly acknowledge we're 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. And with that, operator, let's open up the call for questions.

And thank you. As a reminder, to ask a question, please press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again.

Please stand by while we compile the Q&A roster. And again, that is star 11. And one moment for our first question. And our first question comes from Greg Brody from Bank of America.

Your line is now open.

Hey, good morning, guys. 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, something we should be thinking about?

Hey, good morning, Greg. 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 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 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 were turned online, and I suspect that might be a little bit of commodity driven, hey, let's wait a month and catch an IP next month versus this month. But for the most part, our activity levels have remained pretty resilient. Got it.

And then just to shift to the EE, I think, you know, I'm trying to think about how you're thinking about the ramp there from this point. Maybe you can give us an idea how to think about that and within that question. Based on what you look at today, I think the long-term plan is to fold that into the restricted group. Where do you see timing on that today?

Timing is a little hard to predict, but 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, you know, the EE footprint. So, you know, we still feel very confident that we're going to fill up that, you know, the pipeline. Right now, we've got about a BCF a day contracted. Bill, I believe the ramp has stepped up already, right?

Yeah, Greg. So, you know, as we see it, where kind of Eddie and Lee County production sits today, you know, you're right around that kind of, of wellhead, you know, 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, you know, we saw, you know, you may have noticed Matador announced interest in expanding the former lane plant that we sold to them. putting in a 200 million day cryo there, that's already connected to the pipe, obviously. So these are all good fundamental indicators. And, you know, look, we've seen some rig reductions on the Midland side, but the New Mexico side stayed pretty resilient at, you know, 100 to 110 rigs running.

Yeah.

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

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

Yeah. Not really, honestly. 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 Mewburns 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. 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.

When you say the downstream, you're referring to the long-haul pipelines, is that correct? Correct. That's correct. Just as this question leads to my next one, how are you thinking about sort of the refi today of your capital structure, and what's the current thoughts?

Yeah. Hey, Greg. It's Bill. 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, one being potentially kind of full recapitalization of the second lien and the unsecured. you know, 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, Greg, I think about it as, you know, 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 that 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 put out our 10K with calendar year results and come out with our formal guidance at that time. And I think that would be a pretty good time, Greg, for us to, once we get all that information out to the market, to then go execute on a refinancing process.

That makes sense. And then just a part of that strategy is historically has been M&A potentially to do leverage. You talk about the opportunity set out there today and is that something that you're working on?

Yeah, I mean, 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 just have so much momentum here operationally. It has to be the right deal, and the right deal, again, is meaningfully credit accretive and something that we can kind of get tucked in with good operating synergies that really makes a lot of sense with our footprint.

I appreciate the focus is on growth. Are there a fair amount of opportunities out there?

Yes, definitely good opportunity sets. 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, you know, probably will transact over the next year or so, but whether or not that's, you know, post refinancing or, you know, in conjunction with refinancing, you know, time will tell.

Yeah. And Greg, just to provide a little color to, you know, in the DJ in particular, there's probably five smaller kind of sponsor owned type assets that are strategic to our business. Now, how strategic kind of ranges, you know, some are highly strategic, some are modestly strategic, that, you know, we'll keep an eye on. And then to Heath's point, you know, up in the Williston, there's a couple 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, you know, hitting our numbers and hitting that growth.

I appreciate that. And maybe the last one 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, you'll address it or. Is that something that's on homeowner?

Yeah, Greg, I mean, it's not a huge chunk of the capital structure. It's perpetual. You know, we can continue to kind of accrue distributions there. I think where, you know, 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 chop to get to kind of our leverage target. So it's not a huge focal point for us at the time being. You know, 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.

I appreciate the time, guys. Thanks, Greg.

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