Summit Midstream Partners LP (SMLP) 2017 Q3 法說會逐字稿

Welcome to the Third Quarter 2017 Summit Midstream Partners, LP Earnings Conference Call. My name is Hilda, and I will be your operator for today. (Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Mr. Marc Stratton. Mr. Stratton, you may begin.

Thanks, operator, and good morning, everyone. Thank you for joining us today to discuss our financial and operating results for the third quarter of 2017. 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 or in the News section.

With me today to discuss our quarterly earnings is Steve Newby, our President and Chief Executive Officer, and Matt Harrison, our Chief Financial Officer.

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 the expectations reflected in such forward-looking statements are reasonable, we can provide no assurance that such expectations will prove to be correct. Please see our 2016 annual report on 10-K, which was filed with the SEC on February 27, 2017, as well as our other SEC filings for a listing of factors that could cause actual results to differ materially from expected results.

Please also note that on this call we use the terms EBITDA, adjusted EBITDA and distributable cash flow. These are non-GAAP financial measures, and we have provided reconciliations to the most directly comparable GAAP measures in our most recent earnings release.

And with that, I'll turn the call over to Steve Newby.

Thanks, Marc. Good morning, everyone, and thanks for joining us on the call this morning.

As usual, I'll begin with a few comments on our operations and our quarter, and then I'll turn it over to our CFO, Matt Harrison, for more detail on our quarterly financial results. I'll end the call with wrapping it up by discussing our outlook for the balance of the year.

Yesterday we announced our third quarter 2017 financial results, which included $73.5 million of adjusted EBITDA and $52.9 million of distributable cash flow and a strong quarterly distribution coverage ratio of 1.17x, based on a quarterly distribution of $0.575.

Our third quarter results and our expectations for the fourth quarter continue to be in line with our 2017 financial guidance. We continue to expect to generate adjusted EBITDA of $285 million to $300 million for 2017 and distribution coverage of 1.1x to 1.2x.

Our balance sheet also remained strong with third quarter leverage coming in at 4.16x.

Turning to performance of our operating segments, we had an active quarter, which included a number of highlights. Total operated natural gas volumes averaged 1.83 Bcf a day in the quarter, a new record for the partnership, and a 2.6% sequential increase over the prior quarter.

Gathered volumes for SMLP's Ohio Gathering JV in the Utica averaged 783 million cubic feet a day in the third quarter, up 8% over the second quarter of '17. This was primarily due to the completion of more than 20 wells across the OGC system in July and August.

Natural gas throughput on our operated asset was led by the Marcellus segment, which averaged 554 million cubic feet a day in the quarter, our highest quarterly volume ever and a 15% sequential increase over the second quarter of '17.

Third quarter volumes were underpinned by 11 well completions that occurred late in the second quarter of '17, driven in part by the continued expansion of processing capacity at the Sherwood Processing Complex in July, which brought total processing capacity there to 1.6 Bcf a day. We expect an additional 7 well completions behind our Mountaineer asset in the fourth quarter of '17 and expect drilling activity to resume in the fourth quarter of this year behind the asset, resulting in more than a dozen wells behind the system in the first half of '18. We remain encouraged for our Marcellus gathering assets with a strong outlook for this segment, given MPLX's plan to further expand processing capacity at Sherwood by the end of 2018.

In the Utica, our wholly owned and operated Summit Midstream Utica system gathered 403 million cubic feet a day in the third quarter, down 2.4% sequentially from the second quarter this year. Recall second quarter volumes on SMU were strong given the completion of 11 wells in the first half of the year, along with our commissioning of the TPL-7 connector pipeline in April of this year.

Much of the third quarter was impacted by rolling temporary production outages related to nearby drilling and completion activities and producer well maintenance across our footprint. We expect this work to be completed during the fourth quarter, along with additional well completions which provide us visibility for continued volume growth in the fourth quarter and in '18.

We remain optimistic about volume growth in our dry gas Utica area over the medium term, given the improved drilling economics in the area, coupled with the commissioning of long-haul takeaway pipelines which should help producer netbacks.

With respect to the liquids dynamics in the Utica, we're extremely encouraged by the rally in natural gas liquids prices and are already seeing an uptick in drilling activity across the areas of our system that service the liquids-rich window. As a reminder, our Ohio Gathering system spans more than 800,000 acres in the southern core of the Utica, with exposure to all 3 phases of the play. So it provides us with great diversity across the dry, wet and condensate windows of the play.

Volume throughput in our Piceance/DJ segment averaged 594 million cubic feet a day in the third quarter, which was roughly flat compared to the prior quarter.

Expanding on some of my comments from our second quarter call, we are seeing an uptick in drilling and completion activity across our DJ Basin asset as operators experience success in drilling the Codell and Niobrara formations in the northern extension part of the play. September volumes for this subsystem were up nearly threefold from year-ago levels and are approaching our current 20 million a day of processing capacity. These are higher-margin volumes and contributed to our sequential segment adjusted EBITDA growth in the overall Piceance/DJ segment.

Given our strong outlook in this area, we are excited to announce that we are expanding our DJ Basin operations and will be constructing a new, 60-million-cubic-feet-a-day cryogenic processing plant. Expansion is supported by increasing volumes from our customers and their future drilling plans.

We will finance the approximately $60 million first phase of the project with internally generated cash flow and borrowings under our $1.25 billion revolver.

Our western Colorado operations remain steady and our customers continue to run 2 drilling rigs behind our systems. As I mentioned on the second quarter call, this area is where we saw some completion timing slip from late second quarter and third quarter into the fourth quarter. These completions are currently taking place and we should see subsequent volume increases in the fourth quarter and into '18. Currently we have 80 drilled and uncompleted wells behind the system scheduled to be completed in the next several quarters.

A key event occurred in the Piceance in late July, when Caerus, an existing Piceance customer, completed its acquisition of Encana's Piceance acreage. As a result of the transaction, all 4 of our largest customers are now private-equity backed and singly focused on the Piceance Basin, a dynamic that we think is a big positive for Summit and all midstream operators in the basin. Importantly, as part of the Encana sale we amended our gathering agreement to change the MVCs from an annual [pass or] payment to a monthly payment.

Overall, we're very encouraged by the A&D and drilling activity in the Piceance. We're seeing the technologies and efficiencies perfected in other traditional shale basins being brought to the Piceance by dedicated, singularly focused companies. We have a large gathering footprint in the basin, so we expect to benefit from this renewed over the near, medium and long term.

Our liquids in the Williston Basin had a strong quarter, with volumes of 74,000 barrels per day in the third quarter compared to 69,000 barrels per day in the second quarter. Volumes were bolstered by 17 new well completions in the period, many of which occurred late in the quarter and they'll have a greater impact on fourth quarter results. In addition, our customers have plans to connect an additional 16 wells in the fourth quarter of '17, which we expect will drive volumes higher from third quarter levels.

Many of you may have seen the success that our anchor customer Whiting reported in its third quarter results, with its recent Evitt and Nelson pads, both of which are flowing on our gathering systems. These wells are tracking toward Whiting's 1.5-million-barrel-a-day type curve, and SMLP will benefit from increased production as a result.

We also added a new customer on our liquids gathering system in the third quarter and we received first volumes from them in late October. And they have plans to continue to drill in the area. We currently have 3 rigs drilling upstream of our Baaken gathering systems, which along with an inventory of over 50 DUCs and crude oil firming at $50 to $55 a barrel, is expected to contribute to a stronger fourth quarter and provide tailwinds as we head into '18.

I'll now turn it over to Matt to review our financials in more detail.

Thanks, Steve.

SMLP reported net income of $93.6 million for the 3 months ended September 30, 2017, compared to net income of $2 million in the third quarter of 2016. The third quarter of 2017 included $19.1 million of net income associated with an amendment to a Piceance Basin gathering agreement that accelerated the frequency of MVC shortfall payments from annual to monthly and a $70.5 million decrease in the present value of the deferred purchase price obligation.

In conjunction with the 2016 drop-down acquisition, we recognized the liability on our balance sheet for the deferred purchase price obligation to reflect an estimate of the remaining consideration to be paid in 2020 for the acquisition of a 2016 drop-down asset. We discount the remaining consideration on the balance sheet and recognize the changing present value on the income statement. The change in present value comprises both a time-value-of-money concept as well as any adjustments to the expected of the deferred purchase price obligation.

Adjusted EBITDA for the third quarter of 2017 totaled $73.5 million compared to $76.5 million for the third quarter of 2016.

Relative to the third quarter of 2017, natural gas volume throughput declined on our Ohio Gathering, Barnett Shale and Williston Basin segments and liquids volumes declined on our Williston Basin segment in the third quarter of 2017 compared to the third quarter of 2016. The decrease was offset by increased natural gas volume throughput on our Utica Shale and Marcellus Shale segments.

Adjusted EBITDA in the third quarter of 2017 included approximately $14.8 million related to MVC mechanisms from our natural gas gathering and crude oil transportation contracts. Additional tabular detail regarding MVCs is included in the third quarter earnings release.

DCF totaled $52.9 million in the third quarter of 2017. This implies a distribution coverage ratio of 1.17x relative to the third quarter of 2017 distribution of $0.575 per limited partner unit to be paid on November 14.

CapEx for the third quarter of 2017 totaled approximately $40.3 million, of which approximately $3.5 million was classified as maintenance CapEx. Also, the partnership made $5.9 million of capital contributions related to its Ohio Gathering in the third quarter of 2017.

We had $506 million of debt outstanding under our $1.25 billion revolving credit facility at September 30, 2017, and $744 million of available borrowing capacity. Total leverage as of September 30, 2017 was 4.16 times.

With that, I'll turn the call back over to Steve.

Thanks, Matt.

As we noted on our second quarter call in July, we executed an agreement to build a new 60-million-a-day gathering and processing system for XTO Energy in the Delaware Basin. I'm pleased to report that we are on budget and on schedule and we continue to expect to have the gathering and processing system up and running before the end of the second quarter this (sic) [next] year.

Commercial activity in the northern Delaware remains robust and we recently added our first third-party customer outside of XTO. We expect to be able to share additional information about our continuing commercial development efforts in and around this new asset as we move into 2018.

During the third quarter we also reached an agreement to acquire nearly 50 miles of strategic right-of-way that is fully permitted and runs through the heart of some of the most prolific acreage in the northern Delaware. This is BLM-managed land, so we expect this acquisition to give us a timing advantage as we continue to build out our gathering and processing complex.

In addition to the DJ and Permian expansions which I touched on earlier, we have a number of additional projects that we are evaluating around our existing footprint and we are seeing relative value in organic development as compared to the pricier asset M&A market. We're increasingly optimistic about our prospects for securing additional development opportunities that extend or complement our existing assets.

One other item I'd like to discuss this quarter is the lower mark on our deferred purchase price obligation, or DPPO. While we remain bullish about the outlook for volume growth for our Utica assets over the next several years, our current outlook for '18 is flatter compared to previous expectations, primarily due to volume growth on associated CapEx projects being delayed to the second half of 2018. This is the primary reason why the undiscounted value of our DPPO decreased in the third quarter and now stands at an estimated $656 million.

To SMLP this reduction is really neutral. The DPPO is working exactly as it was intended. The GP bears the development risk during the measurement period and if volume growth is delayed, then the MLP will ultimately pay a lower price for the asset.

Finally, I'd like to address the topic that seems to be on everyone's mind in the MLP sector, which is capital allocation. We are hearing loud and clear the desire from our investors to shift capital focus toward balance sheet strength and distribution coverage.

We believe we compete very favorably in that environment, given our history. Since 2014, 32 of the 50 Alerian Index constituents have effectively cut their distribution, either through an outright cut or a merger that resulted in a cut. Summit has not. And, in fact, since 2014 we have grown our EBITDA by 12% per year. During that time our distribution coverage has increased and our leverage metrics have remained constant. I believe we have managed the uncertainty of the last several years well and I'm encouraged that our outlook today for accretive organic growth is better than it has been over those past 3 years.

We have historically focused on return on capital deployed over growth, and we will continue to be even more focused on this metric going forward. Our long-term leverage target of 4x and coverage target of 1.2x remains intact and achievable and represents levels that we believe are appropriate for our business risk profile and stable cash flow stream. We will endeavor to take a firmer stance on utilizing excess coverage for internal capital needs versus growing the distribution, a posture which we think is prudent, given the evolving MLP landscape.

And with that, I'll turn it back over to the operator and open it up for questions.

(Operator Instructions) We have a question from Tristan Richardson from SunTrust.

Steve, just a little bit on the spend cadence in the Delaware. With the right-of-way acquisition presumably there was some spend in 3Q. But just kind of curious, do you see the bulk of that in the first half of next year? Or will we see 3Q and 4Q of this year have pretty regular spend in the Delaware?

Yes. So I would say first on the right-of-way acquisition, although it was important to us because of permitting timing, from a capital standpoint it's not material. So that's really not what's driving it. But in the third quarter we spent $30 million of our, what, $40 million of CapEx total. I think $35 million of it was related to the Permian in the third quarter. It will be a heavy quarter, probably not that heavy, in the fourth, but, again, fairly heavy in the fourth on Permian spend as well. Some of that, Tristan, is front-loaded, because we bought the plant, we bought compression. Obviously we're buying pipe, too. So some of the big-ticket items are here in the end of '17. And then I would expect the spend in '18 to actually be throughout '18. So even though it goes into service in June, some of our spend obviously will tail into third and I would expect even fourth quarter of '18. But we'll probably have half of the initial $110 million, I would suspect, spent probably by the end of '17.

Oh, that's helpful. And then just curious on the DPPO adjustment, talking about '18 being slightly flatter. Is that purely a function of customer drilling and completion schedules or basin takeaway timing? How should we think about the reason for the shift?

Yes, well, I think those two are probably somewhat related. But I would think of the -- couple things are going on. Obviously in our customer space those guys are under a lot of pressure, like the midstream space, too, on just capital allocation spend. And a lot of our guys are looking at spending within cash flow. So that's going to have an impact. And basis was still poor in the fourth quar- -- in the shoulder months this past quarter. So we do expect that to get helped with Leach coming on here hopefully by the end of the year and then Rover coming in the first quarter. So I do think that will help. But we're just seeing growth get more pushed to the right and that affects the DPPO. I would say nothing about the basin and the reservoir and the rock causes us any concern. If anything, it's gotten better over the last couple of years. But it's more customer just activity being stretched.

Great. And then just last one from me is I guess conceptually as we think about the new project in Weld County and the spend you have planned for the Delaware, directionally should we think with the offset of lower spend in '18 that you might see stable CapEx next year?

Yes, I think overall our CapEx will be higher in '18 than '17, still manageable within our framework of what we're trying to accomplish with prefunding the DPPO and things like that. I don't think it's going to stretch us from a leverage metric. But it will be higher, mainly because, as you mentioned, we have those 2 projects coming on. We expect the Permian to come on in the second quarter, by the end of the second quarter. And then our Delaware expansion sometime late third, early fourth quarter. So we also just won't get -- as those ramp, we won't get a huge contribution. We'll get some contribution in '18, but it will be more so in '19 from those 2 projects.

Our next question comes from Ethan Bellamy from Baird.

Could you let me know how big you think the opportunity is ultimately with XTO in the Delaware? And then, Steve, maybe could you force rank your opportunity set there over the next 2 to 3 years in terms of follow-on investment and expansion?

Yes. I think those 2 are probably tied together, because I think the opportunity with XTO in the Delaware is large. I mean, it's going to be large for a couple different midstream providers there. Just to remind everybody, they have 275,000 acres in really the -- they dominate the northern Delaware from an acreage position. It's contiguous acreage as well, too, so that always helps. It's in 3 different blocks of acreage. And we just acquired right-of-way that basically cuts right through it and saves us about a year of timing from a permitting standpoint. So the opportunity -- we're very focused on making sure we service XTO properly, timely, safely, because they have an enormous -- we have an enormous opportunity set to hopefully add on to our offerings in size with them. There are other, a lot of other, parties up in that area, and both from a producer side and we're obviously not the only game in town from the midstream side either. So we expect additional parties and opportunities, folks to come to the plant. So it's a large opportunity set over there over the next couple of years. I think you're going to see it as another leg of organic growth for us. We also have -- oh, yes, so I'll also mention on -- Matt was just reminding me on XTO. They also announced last Friday on their call that they're going from 20 rigs in the Permian to 30, so by the end of '18. So they're obviously ramping up as well, too. Force ranking on opportunity set, we just announced a project in the DJ, so that's probably got to be up there. We'll still spend -- we're still spending expansion capital in the Utica. I think a lot of folks have heard me talk about we still have haven't added compression on our 100%-owned system. That's a very accretive project for us and that's going to come. These wells are just so big and strong that it's been pushed out. That's also part of the DPPO calculation coming down, too, by the way, is that getting pushed -- compression getting pushed to the right. So that's another area we think we will continue to spend organic capital. And then I would tell you we're also seeing opportunities in western Colorado. We have now extremely focused, well capitalized, private-equity-backed companies that are very active out there, and so that's going to lend itself to some -- we hope to and we think to some growth opportunities out there as well, too.

Okay. And then one more big-picture question. As you're talking with producers who are all belt tightening and trying to live within cash flow, what's changed in terms of what they're looking for? Are they still looking for primarily up time? Are they just trying to get their pencil as sharp as they can on the best rates available? I mean, where is the competitive frontier, if you will, between you and some of the other guys who I know -- I mean, XTO is a marquee customer and a lot of people would love to get in and have that business. And what led you to win that?

Yes. It varies with our customer base on what they look for. Some are -- they're not all the same. Typically a customer -- I've commented on this publicly. A customer like XTO is -- they're all price sensitive. I don't want to make -- I mean, that's just a given. But some also value the ability to execute, the ability to do it safely, the ability to do it on time, and the ability to be flexible with their changing plans. Those are all factors that go in -- when you're a company like Exxon, there's multiple factors versus just who's the lowest price. I can tell you we weren't the lowest price in the Permian for them. But I think if you talk to them, they have a lot of confidence in our ability to execute, given what we've done for them in the Utica. So it varies. Some producers are much more price sensitive and focused. But I will tell you, most are really focused on can you deliver what you say you're going to deliver. Do you have a track record of doing that and can you do it safely, obviously? So it varies in the competitive environment in different basins. You know, we're now in 5 or 6 of them. That varies as well, too. So it's not a -- it's a little bit of a mixed bag. But producers are very -- their capital's tight, too. They're very focused on price and execution right now.

And would you say there's a -- it does. Is there any shift in the desire to structure, say, POP versus [key pole] versus [feet] or to execute MVCs?

MVCs, depending on where you are and the dynamics of the area. We will have commitments on our DJ asset. So that's good. We have tended -- we will give up upside sometimes to protect the downside. That's been a strategy of ours. I think we've said that publicly in places. We are not big commodity price takers. Our customers know that. So our processing, this new transaction in the DJ's 100% fee based. Our transaction in the Permian, our deal in the Permian, is 100% fee based. So we're just not big commodity price takers. I think most customers work with us on that end as well, too. And it's just a matter of how the ultimate service looks like to them. So I don't think there's a push one way or the other. There is obviously some aggressiveness out there in the space on -- and some folks, some other peers, have led with paying for acreage commitments and things of that nature. So that's a phenomenon that we're trying to wrap our head around a little bit here over the last -- that we've seen over the last 6 months come into play.

That was helpful, Steve.

Our next question comes from Elvira Scotto from RBC Capital Markets.

A couple of questions. First on the DJ Basin project that you announced, do you expect sort of the typical Midstream return on that project? And what's the timeline that you get to that return?

I would say, yes, that project is -- think of it as right in our 6x to 8x where we want to be organically. We expect this one to ramp up pretty quickly, given activity levels going on in the area. Rigs have been working in that area pretty consistent. I think we've got a rig there now and then we've had 1 or 2 working pretty consistently through the year. So we'll be pushed, Elvira, on this one to get the plant going in time to meet sort of producer volumes. So I expect this one to ramp up pretty quickly. So we'll get to that level I would expect within the first 12 months or so. The Permian, I think we've said there we're more -- just to position against that, we're more 8x to 10x. I expect us to get to our 6x to 8x. That one will probably take a little bit longer. It will come up in June. And we expect a strong ramp there, probably more '19 related, so 6 months or so probably behind the ramp of the DJ.

For the Permian, that's to get to 8 to 10 or is that to get to 6 to 8?

Get to 6 to 8. Yes.

Oh, got you. Great. And then just the other question that I had is, can you expand a little bit on your comments of taking a firmer stance on using excess cash to fund capital versus distribution growth? How does that fit in with the 1.2x coverage target? Is the plan to kind of finance the equity portion of your growth CapEx with internally generated cash? Or just how should we think about that going forward?

Sure. So I think, Elvira, if you think about right now, a distribution increase just really isn't in the cards currently as far as our thought process. Right? So if you take our current coverage on a quarterly basis, a little over $7 million, multiply that by 4 you get close to $30 million and then with a growing kind of EBITDA case. Right? So that current $30 million of what I'll call excess cash on an annual basis and then growing as we roll into 2018, we would consider that to be -- reinvest in the business versus distributing and raising more capital in the capital markets. So that's kind of what we've been focused on. And then, the coverage will then basically just increase basically. Right? Now, one of the governors on all this is leverage. And so as we continue to build up Northeast, the Permian and the like -- so we have to kind of keep those leverage statistics in mind as well. But, again, we've been kind of opportunistically taking out our DPPO commitments. We've had some ATM issuances in the second quarter. We actually had no ATM issuances in the most recent quarter. So we'll continue on that pace.

Got it. And in terms of financing the DPPO, are you looking at alternative ways of financing, i.e., potentially doing some preferreds?

Yes, I'll say that the preferred kind of activity has certainly been noticed by Summit I think over the last few months. A lot of that has been done by the investment-grade guys. And so we're -- I think on the retail side there's opportunity as well. So, yes, as we look to opportunistically pick our spots, that would certainly be one that we would think we would consider.

(Operator Instructions) The next question comes from Mirek Zak from Citigroup.

I really just wanted to ask if you can provide a little bit more color around the push-out of the Utica development into maybe later 2018. And do you see any concerns over that possibly being pushed out further?

Yes, it's Steve. So part of it is we have Ascent drilling on our SMU acreage. And we'll bring the first volumes on, expect to here in the fourth quarter. That's pretty much set. And then, no, we're working pretty closely with them on building out to the pads they're going to be bringing on in '18. So I think we feel pretty good about that outlook. It has gotten pushed till the latter part of '18 as it stands right now. And so that was part of what's around our commentary. And then our other big customer, Gulfport, I mean, they're public so they give good commentary around it. I think they're focused, like a lot of E&Ps, about drilling within cash flow. And so that's part of what I would say is the elongating of the development in the Utica. On the positive side, I mentioned it in my prepared remarks, we are seeing increased activity in the condensate and NGL windows. And I think we anticipate that still occurring in '18 as well, too, as NGL prices have rallied here a bit. And then the other thing, the final piece I would mention is compression getting pushed out. We still -- just so everyone knows, we've had volumes falling now on SMU for over 2 years, and we've yet to put compression on our system. So that means they're basically -- the wells are strong enough to still get into the interstate system at 1,000-plus pounds. So they're just big, big wells and compression's gotten pushed out. That's a little bit of a -- you could take it as a negative to us, because it's an accretive project. But it's a positive in the sense of how big these wells are in the Utica. The final point I'll make is I want to make sure everyone understands the DPPO is working exactly like it's supposed to. As that growth got pushed out the price at which we buy those assets, the MLP, has come down. And so, we've made this point since we did the transaction. I think this is a good quarter to see how that works. The risk of this extension, or the pushing out of growth, is not a risk the MLP is bearing. It's a risk the GP is bearing.

At this moment we show no further questions. I would like to turn the call back to Mr. Stratton for final remarks.

Great. Well, thank you, everybody. Have a good weekend and if you have follow-ups, please give us a call and we'll help you out. Thank you.

Ladies and gentlemen, this concludes today's conference. We thank you for participating. You may now disconnect.