Summit Midstream Partners, LP
Q3 2018 Earnings Call Transcript

Published: 9 Nov 2018

[Operator:]

Good morning and welcome to the Third Quarter 2018 Summit Midstream Partners, LP Earnings Conference Call. My name is Paulette, and I’ll be your operator for today’s call. At this time all participants are on a listen-only mode. Later we will conduct a question-and-answer session. [Operator Instructions] Please note that this conference is being recorded. I will now turn it call over to Marc Stratton, Senior Vice President and Treasurer. You may begin sir.

[Marc Stratton:]

Thanks, operator and good morning, everyone. Thank you for joining us today to discuss our financial and operating results for the third quarter of 2018. If you don’t already have a copy of our earnings release, please visit our website at www.summitmidstream.com, 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; Matt Harrison, our Chief Financial Officer; Leonard Mallett, our Chief Operations Officer; and Brad Graves our Chief Commercial Officer, and Brock Degeyter, our General Counsel. 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 of such expectations will prove to be correct. Please see our 2017 Annual Report on Form 10-K, which was filed with the SEC on February 26, 2018, 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.

[Steve Newby:]

Thanks, Mark. Good morning everyone and thanks for joining us on the call this morning. As usual I’ll begin with the few comments on the quarter and I’ll turn it over to Matt for more detail on our quarterly financial results. I’ll then wrap up the call by giving an update on our Double E project and discussing our preliminary outlook for 2019. Yesterday we announced our operational and financial results for the third quarter, adjusted EBITDA in the third quarter totaled $73.4, which was in line with both the prior year period in the second quarter of 2018 results. We are on track to hit our 2018 adjusted EBITDA guidance of $285 million to $300 million. Distributable cash flow in the third quarter was $43.6 million, which led to a distribution coverage ratio of 0.96 times. We had a pretty full maintenance CapEx spend in the quarter, totaling more than $6.4 million, which impacted quarterly distribution coverage. The higher maintenance CapEx was due to seasonality and we continue to expect full year 2018 maintenance CapEx to range from $15 million to $20 million. And we expect distribution coverage to improve in the fourth quarter with full year 2018 coverage at approximately one time. A key component of our third quarter results was the high level of drilling and completion activity by our customers in the Williston segment. Liquids volumes averaged almost 97,000 barrels a day in the quarter, a new record for SMLP and increase of over 30% from the prior year and 9% quarter-over-quarter. Higher volumes were driven by strong well results and consistent drilling and completion activity with 26 new wells turned in line in the quarter. Our customers are currently running three drilling rigs upstream of our systems. During the third quarter certain of our Williston customers temporarily curtail production from a number of existing wells for nearby simultaneous drilling and completion activities, which along with the produced water constraints at third party disposal wells negatively impacted third quarter volumes by an estimated 12,000 barrels a day. Many of these constraints has since been lifted and liquids volumes in October or an excess of 100,000 barrels a day. Outlook for our Williston segment is strong and we are forecasting higher liquids volumes for the fourth quarter of 2018 and into 2019. As previously discussed or completing now at the bottlenecking project our crew gathering system that will add approximately 30,000 barrels a day to the system. We can plan to complete this project before your end. Also, our commercial teams, enhanced our customer portfolio by adding three new gathering agreements in the quarter, all of which are expected to further boost activity going forward. In the Utica, our SMU segment, and our OGC segment experience differing results for the quarter. For SMU volumes were down approximately 14% quarter-over-quarter mainly due to drilling and completion activity that’s currently going on in the area that required temporary volume curtailments of existing production. This activity costs us approximately 40 million cubic feet a day of volumes on the system. Activity remains steady with one drilling rig working upstream of our systems since the second quarter of 2018 and scheduled to remain there throughout all of 2019. We expect to see a robust level of drilling and completion activity at SMU with completions beginning now and remaining steady through the end of 2019. One change in activity we became aware of in the third quarter is the shift by one of our primary customers to focus on the wet gas and condensate windows of the Utica Shale behind OGC. Well, this is countered our prior expectations, it is in a major surprise as improving economics and mixed higher crude oil and NGL prices make these liquid rich areas very economically attractive. We are already seeing an uptake in activity levels associated with our Ohio Gathering segment, which reported 10%, quarter-over-quarter volume growth driven by 20 new wells connected in the quarter. Our customers are currently operating three rigs upstream of OGC, and we expect this activity will continue for the foreseeable future and lead to 2019 volume growth. SMU and OGC are two of the sub systems, including in our 2000 dropdown and transaction. So this geographic switch away from the dry gas window and into the wet and condensate windows has captured in our DPPO calculation. As a result, we have reduced the estimated undiscounted amount of the DPPO from $538 million to $454 million primarily based on fewer new gas – new dry gas wells at SMU in 2019, which really just relates to timing, but impacts the DPPO significantly. The ship was partially offset by increased expectations, as I mentioned in the wet gas area and lower CapEx related to connecting customers new pads in the dry gas area. Just a few other key points on the Utica before we move on. First, although the expectation for activity in the dry gas window was lower than we expected last quarter, that’s reflected in the DPPO. We still expect solid growth in this area for many years to come. In the wet gas and condensate windows, we have seen a significant increase in activity over the past several months, which will lead to nice volume and cash flow increases in 2019. Further, the discussions we’re having with customer lead us to be bullish in the Utica well beyond 2019 and spanning across all three windows, condensate, wet gas and dry gas of the basin. Second, the DPPO was working exactly as design and that its adjusting with changes in the performance of those assets. I know it seems like ages ago, but when the assets were dropped down in the first quarter of 2016, crude was trading below $30 a barrel, natural gas was trading at around $2 a barrel or $2 an Mcf and energy capital markets we’re in a state of disarray. In connection with the dropdown our general partner agreed to where the development risk associated with these assets, which is enables SMLP to acquire these assets at an attractive six and a half times multiple trailing EBITDA. Why we couldn’t have predicted early in 2016 was the duration of the commodity cycle. Perversely, the extension of the cycle has benefited the MLP as it relates to the DPPO, because while the payment amount has come down, we see robust growth in these assets in 2020 and beyond. So SMLP will benefit greatly from this post 2019 growth outlook. Moving to our Barnett segment, volumes in the third quarter were down approximately 12% from the prior quarter. This was an exacerbated by our required annual regulatory shutdown, which coincided with temporary volume curtailments of existing well pads with new drilling and completion activities – sorry, on well pads with new drilling and completion activities. The scheduled maintenance affected volumes for five days in September and together with the regulatory shutdown costs us about $15 million cubic feet a day during the quarter. Late in the third quarter, a DFW Midstream customer completed five new wells and exit rate volumes in the quarter averaged approximately 260 million cubic feet today. We’re forecasting four new additional well connections in early 2019, which we expected positive impact volumes into next year. Activity in the Piceance/DJ segment was focused on our DJ basin system, our team is working diligently to commission our new 60 million a day processing plant, which we expect to begin later this year. Currently volume throughput on the DJ system has constrained by the existing 20 million a day plant, and in the third quarter, the DJ system operated at nearly full capacity. 39 new wells were completed in our Piceance/DJ segment during the quarter, including 23 new wells upstream of the Niobrara G&P system. In addition, our DJ customers are currently running four rigs behind our service area and building an inventory of docks to immediately utilize the new processing capacity once it becomes available later this year. At these activity levels we’re already evaluating subsequent expansions of the processing complex. Turning to our northern Delaware operations, our team has focused on commissioning or lane processing plant, which we expect will occur in the fourth quarter with a steady ramp in volumes throughout 2019. This facility was originally underpinned by XTO Energy. However, in less than a year and a half, we have executed three additional gas processing agreements in our negotiated agreements with other potential counterparties. Our customers are currently running two drilling rigs upstream of our gathering and processing system and like the DJ, this is an area where the activity levels are requiring us to begin planning subsequent plant expansions even before the initial project has been commissioned. Our gathering and processing projects in the northern Delaware and DJ basins have accounted for the majority of our CapEx expenditures thus far in 2018 with practically zero associated cash flow. Our leverage ratios and distribution coverage ratios have also been impacted. But despite this our balance sheet remains in good shape. We have significant liquidity and ample leverage capacity, which has as 9/30 stood at 4.02 times. We expect our distribution coverage ratio to improve throughout 2019 as we more fully utilize our assets and begin to generate meaningful cash flow from our investments in the DJ and in the Delaware. We do not forecast the need to access the equity capital markets in the near term and we expect to be very well positioned for the DPPO payoff in 2020. With that, I’ll turn it over to Matt to review our financial results in more detail.

[Matt Harrison:]

Great. Thanks, Steve. SMLP reported net income of $57.5 million for the third quarter of 2018 compared to net income of $93.6 million in the third quarter of 2017. Third quarter of 2018 included $37.2 million of noncash income related to the deferred purchase price obligation or DPPO. Net income in the prior year period included $70.5 million of noncash income related to the DPPO. Adjusted EBITDA for the third quarter of 2018 total $73.4 million compared to $72.5 million for the prior period. The $100,000 decrease in adjusted EBITDA was primarily due to natural gas volume decreases on our operated natural gas systems offset by liquids volumes increases on our Polar and Divide systems. Adjusted EBITDA in the third quarter of 2018 included approximately $15.8 million related to MVC mechanisms from our natural gas gathering and crude oil transportation agreements. Additional tabular details regarding MVCs is included in the third quarter earnings release. Total operated natural gas volumes average 1.6 billion cubic feet per day in the third quarter, a decrease of 10.8% compared to 1.8% [ph] Bcf/d in the prior year period. SMLP experience, natural gas volume declines on all of our operated systems, excluding the Niobrara G&P system in the DJ basin. Ohio Gathering average 797 MMcf/d in the third quarter of 2018, if 4.5% increase compared to 763 MMcf/d in the prior period. In the Utica our wholly owned and operated Summit Midstream Utica system gathered 357 MMcf/d in a third quarter, a decrease of 11.4% compared to 403 MMcf/d in the prior year period and 14% relative to the second quarter of 2018. Natural production declines in our SMU system were offset by increased volumes from the TPL-7 Connector, which was started in the second quarter of 2017. Also, SMU’s third quarter volumes were impacted by approximately $40 million a day of temporary volume curtailments related to infill drilling and completion activities. Volumes on the TPL-7 Connector average 148 million a day in the third quarter of 2018 compared to 74 million a day in the prior period and 124 million a day in the second quarter of 2018. Currently our customers have one rig working on SMU. For Ohio Gathering volume throughput in the third quarter of 2018 was 797 MMcf/d, a 4.5% increase compared to prior period and a 9.6% increase compared to the second quarter of 2018. Volumes increased relative to prior year and prior quarter due to 20 new wells that were brought online late in the second quarter of 2018 and 20 new wells brought online in the third quarter of 2018. Currently our customers have three rigs working in the Ohio Gathering service area. Our liquids gathering business in the Williston basin average 97,000 barrels per day in the third quarter up 31% from the third quarter of 2017 and up 9% compared to the second quarter of 2018. 10 new wells were brought online in the first quarter of 2018, 20 new wells were brought online in the second quarter of 2018 and another 20 new wells were brought online in the third quarter of 2018. SMLP estimates approximately 12,000 barrels per day were offline during the third quarter due to certain customers initiating temporary production curtailments on existing wells for nearby drilling and completion activities or produced water capacity constraints at third party disposal wells, which necessitated trucking activities. Currently our customers have three rigs working in our Williston basin service area. Our Piceance/DJ basin segment average 571 MMcf/d in the third quarter of 2018 down approximately 4% compared to the to the third quarter of 2017 and relatively flat to the previous quarter. Natural production declines have been partially offset by the completion of 50 new wells in the first quarter of 2018, 37 new wells in the second quarter of 2018, and another 39 new wells in the third quarter of 2018, including 23 new wells upstream of our Niobrara G&P systems in the DJ basin. In November 2017, we announced plans to develop a new 60 MMcf/d processing plant expansion in the DJ Basin, the new plant is expected to be commissioned in the fourth quarter. We expect our DJ basin system to experience volume growth throughout the balance of 2018 and continue through 2019. Currently, our customers have four rigs working at a Piceance/DJ segment, all upstream with the Niobrara G&P system in the DJ basin. And the Barnett volume throughput average 232 MMcf/d in the third quarter of 2018 down approximately 9% compared to the third quarter of 2017, and down approximately 12% from the second quarter of 2018. Volume throughput in the third quarter was impacted by a temporary curtailments associated with simultaneous drilling and completion activities and by an annual regulatory shut down, which resulted in little to no volumes were approximately five days in September. We estimate these activities impacted volume throughput 15 million a day for the quarter. Five new wells were brought online later in the third quarter. Volume throughput in our Marcellus segment average 4590 MMcf/d feet per day in third quarter down approximately 19% compared to the third quarter of 2017 and approximately 14% from the second quarter of 2018. Compared to the prior period volumes were impacted by the natural production of clients of 27 new wells brought online in 2017 and nine wells that came on late in the first quarter of 2018. No new wells are expected for the balance of 2018. Turn it back to the partnership. Distributable cash flow total $43.6 million in the third quarter, which implied the distribution coverage ratio of 0.96 times relative to the third quarter distribution of $0.575 per common unit to be paid on November 14. CapEx for the third quarter totaled $46.6 million, of which $6.4 million was classified as maintenance CapEx. We have $384 million outstanding under our $1.25 billion revolving credit facility at September 30, 2018, and $866 million of available borrowing capacity. Total leverage as of September 30, 2018 was 4.02 times. SMLP also reaffirmed its 2018 financial guidance. We expect 2018 adjusted EBITDA to range from $285 million to $300 million. Total CapEx is expected to range between $175 million and $225 million, which includes $15 million to $20 million of maintenance CapEx. We expect distribution coverage for the full year to approximate one-time. SMLP introduce its preliminary view with respect to 2019 financial guidance, we expect adjusted EBITDA growth of at least 10% over 2018. We expect distribution covers in the fourth quarter of 2019 to exceed 1.15 times. With that, I’ll turn the call back over to Steve.

[Steve Newby:]

Thanks, Matt. So let me first begin by discussing the Double E pipeline, which is our project to provide up to 1.5 Bcf/d of residue natural gas transportation capacity from the Delaware Basin to the Waha Hub. We conducted a binding open season process in the third quarter to prevent binding open season our investment thesis was affirmed, which is that a pipeline solution is required to evacuate a significant amount of residue natural gas out of New Mexico to Waha. In addition to the initial precedent agreement with XTO Energy for up to half a Bcf of firm capacity. We have executed additional press agreements with new shippers and we are continuing to discuss significant firm volume commitments with other prospective shippers. We will make our final investment decision on Double E once these negotiations have concluded, as these discussions could have a material impact on the scope of the project. Our timing on FID is not impacted our filing process and we continue to target a second quarter of 2021 in service date. This is a large industry solution as requiring shippers in conjunction with SMLP to make long-term financial commitments. From Summit standpoint, we are going to remain disciplined and make sure we have the right level of support and ultimately economics for our unit holders before we FID the project. Additionally, we’re reviewing numerous financing alternatives in parallel with our FID process, both on balanced sheet and off balance sheet and including Exxon’s option to participate in the project. We expect to outline or financing plan for Double EE when we FID the project. We also expect to more closely evaluate noncore asset sales in 2019 as we focus our capital investment in our four key growth areas, Delaware, Utica, DJ, and Bakken. Looking ahead to next year, yesterday, we released a preliminary view of 2019 adjusted EBITDA, which we expect to be up at least 10% over 2018. These results will translate into strong distribution coverage and leverage ratios, which will leave SMLP in a very good position to address the DPPO. We will continue to refine this forecasts and expect to provide more specific disclosure in our next earnings release. 2018 has been a transformational year for Summit as we have firmly exited the commodity price cycle downturn in our positioning ourselves for significant growth and adjusted EBITDA in DCF per unit. I’m proud of our team for executing on operational and commercial milestones and I’m encouraged by both the macro landscape and the activity of customers and our operating footprints. The activity and opportunity for organic growth development is the best we’ve seen since 2013. As producers seek midstream service offerings Summit continues to benefit from our reputation as a high quality operator, and I’m grateful to our team for their dedication to this reputation. With that, I’ll open it up for questions.

[Operator:]

Thank you. [Operator Instructions] And our first question comes from Tristan Richardson from SunTrust. Please go ahead.

[Tristan Richardson:]

Hey, good morning guys.

[Steve Newby:]

Hey, good morning.

[Tristan Richardson:]

With respect to any express, we really appreciate all the additional comments on your commercial efforts there. Helpful. I think you guys commented that the ultimate timing will depend on the outcome of a few potential customer discussions you’re having now that could flex the scope of the project. Can you talk about what point an FID might impact the start date? I mean, we assume a few weeks here, there aren’t going to impact anything, but just curious, if FID pushes out further at what point does that to 2Q 2021 dates start to become more subject to review?

[Steve Newby:]

Yes. That’s a good question. So the real key is – we expect to file for our 7C permit, Tristan, in late first quarter towards the end of February, beginning of March. And that’s really what the ultimate from a timing perspective is working back from that key milestone in our thoughts around the process. So I don’t expect our commercial discussions to go that long, frankly. We’re actively working it now, but that – but if you wanted to put a marker in as far as a timing that, that would be where I’d point you.

[Tristan Richardson:]

That’s helpful. Thanks and then when you talk about kind of flexing the scope depending on customer discussions, is there a possibility that you could see the upsides from the “up to one five” in terms of the scope of the project?

[Steve Newby:]

Yes, I think, what we’re seeing you may have noticed the nuance of the 1.5, I think before, we basically sat around a Bcf, that was by design, and then I would say beyond that level, it comes down to adding compression to the pipe in the level of that add. So you have very incremental expansion opportunities beyond that, that one 1.5 Bcf which is, effectively adding compression and obviously that’s got to be supported by our customers as well too because it’s capital from us. So, that’s how we view it.

[Tristan Richardson:]

That makes sense. And then just lastly for me. As you talk about early evaluations of expansion on the processing side in the Permian. I assume that expansion there goes in hand in hand with the Double E project, but curious if – if any potential expansions would be a significant step up or you might have an expand as you go scenario either modular or an increments of 60 a day, et cetera, type of approach, one versus the other?

[Steve Newby:]

Yes. Let me, let me take that a couple of ways, because I want to talk about a little bit about the Permian and I’ll finish up on the DJ, because that’s important too. So on the Permian I wouldn’t necessarily make the complete connection between our processing complex and the expansion of it, at relates to Double E, Double E is going to have three or four sea points for gas along the way. So it’s not going to just be the lane complex. It’s going to be multiple over sea points. So it’s an industry solution that was desperately needed, but it’s not just tied to lane. So I think that that’s important. Now on lane. I think what we have to plan for, and this goes for the Delaware to earth for the DJ also is it takes us about 12 months to 14 months to get a new plant in. And so we have to look in – and that’s not unusual in our space. We have to look out, a year ahead. I’m happy having conversations with our customers and your head to try to keep up with their activity. And what we’re trying to tell you is based upon that view, we’re having to evaluate expansions at both places. I think, the easier one from our outlook is probably the DJ given what we’re seeing in the level of activity we’re seeing. Our area in the Delaware is – it’s the northern part of the Delaware. It’s a much higher oil cut, than what most of you guys are used to see in down the state line area. This is 80 – 80% plus will cut well. So it’s being – drilling is migrating and moving north and so we’re working with our customers on that. But we’re not going to – we’re not going to do an expansion and neither place unless we feel like it’s supported by their level of activity. But we are already evaluating those And I would say on the Permian on sizing, we haven’t just – we just haven’t made that determination yet. It’s just a little too early on whether we do we do another 60, do we do a 200? So all of those are going to be in consideration here over the next couple quarters.

[Tristan Richardson:]

Great. Very helpful. Appreciate it, Steve.

[Steve Newby:]

Yep. Thanks.

[Operator:]

Our next question comes from Mirek Zak from Citigroup. Please go ahead.

[Mirek Zak:]

Hi, good morning everyone.

[Steve Newby:]

Good morning.

[Mirek Zak:]

Just in the Williston beside your debottleneck in project there, can you comment on your takeaway options out of the face in and what kind of tightness you or your customers might be seeing an exit options, and how much remaining available sort of reversed preserved capacity you have to get that product out of the basin?

[Steve Newby:]

Yes. Great question. So our – our issue really – we’re very well positioned on the takeaway point because we deliver, we have three main options. We delivered a rail so cold, which is crested with asset, which delivered to DAPL and we deliver to Emrage. So all three. We definitely, over the last two quarters have seen volumes move between those assets, mainly between DAPL in rail, frankly as, as basis widened zone on the crude side you’ll see – you’ll see rail pickup. But on the takeaway side, we’re fine. That’s not our issue and the bottlenecking is really on her own system. We’re just seeing tremendous volume growth. We really started this. This is a small project. It’s just highly incremental to us. We started it about a quarter and a half ago, I think, I talked about it on the last call and we’re going to finish it here by the holidays. And it’s going to give us another 30,000 barrels a day of capacity on her own system. So our constraint isn’t on takeaway was that that project’s meant for our own, our own gathering system and we expect it to be used throughout 2019. It’s a pretty high level of act, not only high level of activity there Americans, we’re seeing bigger wells as profit loading really takes hold in the basin. So we’re seeing bigger wells.

[Mirek Zak:]

Okay. Thanks for that. Can you provide a little more color around your outlook for the Piceance/DJ volumes further down the road? I guess this goes with your comments around potential projects, but if you think at some point that your volume is there, might get beyond exceed the MVC levels for the customers that it pertains to and that you might bring that segment to basically drive steady cash flow growth?

[Steve Newby:]

Yes. So let me split the two. The DJ from the Piceance. I think in the DJ, we’re going to cut this plan on here in the next – next month or so. And we think it’s going to be a pretty steady ramp in fairly quick ramp throughout 2019. And as I mentioned, we’re already viewing or reviewing a potential expansions there, from what we’re seeing and what our discussions are with our customers. So our outlook in the DJ is, I would say very robust, given what – what we’re seeing and what we’re talking to our customers about. The Piceance is different. We’re seeing a lower growth there and even some declines there’s, what we’re expecting there. That area is getting hit pretty hard by the basis backup from Waha up into Western Colorado. And so that, that’s affecting our customers there. As you noted, we’re pretty highly underpin there, but we don’t expect significant growth from the Piceance and actually are expecting in 2019 declines in that area. So, so that’s why I would split those two areas in part. I know they’re reporting the same segment, but that there’s two different dynamics going on in each one.

[Mirek Zak:]

Okay. And just one quick final one, on the M&A front. I’m just curious if you had any conversations regarding any of your assets or if you were to look at that as a potential way to possibly raise capital to focus on higher priority projects or if that’s just something you’re not entertaining right now?

[Steve Newby:]

I would say yes and yes. I’m probably shouldn’t leave it there with you. But yes, we have conversation. I’ve had conversations and yes, we continued to look at. I think, what I wanted to get across in my commentary is there’s four key growth areas to us. The capital markets are constrained, asset sales are going to become, as they are with other of our peers are going to become a renewed focus for us as well too. As we look to focus dollars on these four key growth areas. We are reviewing other noncore assets in our portfolio and we’ll continue to do so.

[Mirek Zak:]

Can you comment on any, which sort of regions are a little, a little more interest than not or?

[Steve Newby:]

So I would put it has – what are our core growth areas, and the Permian, the DJ, the Utica and the Bakken. And you can sort of take it from there on what’s not our core areas and where we may be refocused in dollars.

[Mirek Zak:]

Okay, great. Excellent. Thanks for the color. Thank you very much.

[Operator:]

[Operator Instructions] And we do have a follow-up question from Tristan Richardson from SunTrust. Please go ahead.

[Tristan Richardson:]

Hey guys. I have got you, just keep it going. Just kind of curious as you look at these potential expansions in some of your growth areas and understanding it’s early days and still evaluating and having commercial discussions with customers, but curious just general timeframe, I mean, could we see potential expansions is early as kicking off in 2019? Is it too early say at this point?

[Steve Newby:]

Yes. I think kicking off, yes. Again, it takes a year or so to get up a plant in. I would use 14 months is a good marker. So for what we’re seeing as far as volume growth in both areas in both the Permian and the DJ. Yes, it’s something we could absolutely kick off in 2019. How much it impacts 2019 from a CapEx standpoint, it’s probably too early to be determined. And we’re going manage that pretty closely given Double E, given that the differed payment, but yes, I think we’re evaluating them now or what we need to do.

[Tristan Richardson:]

Understood. Thanks guys very much.

[Operator:]

Our next question comes from Ethan Bellamy from Baird. Please go ahead.

[Ethan Bellamy:]

Hey guys, I apologize, this is redundant, but I turn little late. I mean you guys have an uncompetitive cost of equity capital with your yield and an increasingly off spec incentive of distribution, right structure. Is it your contention that you can fully finance Double E without tackling the structure or the cost of equity?

[Steve Newby:]

Yes, it is. I think we did – we’d mentioned it in or I mentioned in my prepared remarks, I think Double E we’re getting, not only did we have significant commercial interest on the project. We have significant interest from folks wanting to help us finance that either on balance sheet or off balance sheet in creative way. So we expect to be able to do Double E in the way the capital lays out, it’s really over the next three or four years. So it’s not all in one year. So the answer is yes, we don’t expect to have to address our distribution to finance Double E.

[Ethan Bellamy:]

Okay. And then longer term the structure and IDRs?

[Steve Newby:]

So we pay about $8 million to $8.5 million IDR cash flow today. It’s definitely on our radar, as you would imagine, especially given the growth we expect over the next several years. And so it’s one of the things we’re going to have to look at and address. I don’t think there’s any set time period for that, but we are going to – it’s not a – it’s not a huge burden for us right now, but it’s going to become a bigger one is given our, our growth profile for the next several years. So, I don’t have an answer as far as timing, but yes, it’s on our, it’s definitely on our radar to address.

[Ethan Bellamy:]

Okay. So is it safe to say, to sort of craft the value proposition for investors is that the distribution is going nowhere, so by now you’re going to get your 15% and then as we grow EBITDA that should probably move up as leverage metrics and coverage approves.

[Steve Newby:]

Yes. I don’t think we’re real incentive to grow the distribution at this level. But we don’t feel like a distribution cut is the answer to all of our problems here. We feel like we can grow accretively given what we’re seeing and how we feel like EBITDA is going to grow with coverage to grow into that. But you’re absolutely right, we’re not ready to address the distribution. Something would have to change given what we’re seeing to do that. And we just don’t see it right now and you’re getting paid handsomely to see that growth. So I think that’s a good way to put it. And that’s how we’re seeing it. We expect north of – we expect double digit growth in 2019. And our outlook for 2020 I know people are focused on a lot on the Utica with DPPO, but I would tell you our outlook for the Utica right now is the strongest it’s been in quite some time and its going to grow north of 15% for less than 2019 and we expect it to grow even more in 2020 and beyond, which is – which is going to be very valuable to the MLP because they’re not going to have to pay for that beyond 2019 growth.

[Ethan Bellamy:]

Okay. And so for somebody new to the story who looks at a 15% yield, I mean, in a lot of cases there’s nothing indicator that something’s wrong. How would you in sort of respond to that cosmetically and, and if there were to be something that, that threatened to distribution, how would you summarize that? Would it be, general downturn in commodity prices that impacted volumes and then ultimately threatens the growth?

[Steve Newby:]

Yes, I think it has to be performance related. And growth related, if we felt like we just couldn’t get done what we needed to get done. We just don’t – we were elaborative four times. And we feel like we have a solution for the DPPO to pay that over the next two years. We have until, I think one nuance for folks looking at us and our story that we have until the end of 2020 for fully repay the DPPO right? So we have payment during the first half and then, but we can stretch it out to 2020 as well too. So we, we feel like we have a good story there, but it has to be performance related and I think we’re happy now that we’re finally seeing growth after a couple of years of being flat. We’re expecting – we think double digit growth is actually pretty good in the EDTIDA. So we’d have to be related to that, Ethan and something materially change for us to addresses the distribution on. Again, we just don’t think trying to cut your distribution to target some magical yield to the investor base. I just don’t think that’s worked. I think others have tried that and you cut your distribution because you have to know because you want to and you typically do it because of leverage. And we don’t view our leverage is an issue.

[Ethan Bellamy:]

Okay. Thank you for tolerating my questions. I appreciate it.

[Steve Newby:]

Not tolerating all. And I think congratulations in order for all of us on 1/12. We appreciate all the updates from you.

[Operator:]

Our next question comes from Kyle Mayfrom Capital One. Please go ahead.

[Kyle Mayfrom:]

Hey, good morning guys. Just one quick one for me. Looking at your initial outlook for 2019 with 10% growth year-over-year. Can you give us any preliminary thoughts about what’s going into that and if it factors in the potential asset sales that you are considering?

[Steve Newby:]

So I’ll take it in reverse order. The answer’s no, you can’t. We don’t factor in M &A either way. It’s hard to do that. So the answer is no on that. First, let me say, it’s at least 10%, I want to make that clear. We didn’t come out with the market that is 10% we think it’s going to be at least a double digit growth. What’s going into it? We have two plants that contributed zero, in fact, negative, because we had expenses related to them in the DJ, in the Permian two plant expansions. So we’ll be starting up the DJ plants underpinned by significant volume commitments. And so you’re going to see a big ramp as soon as that plant starts up, due to the receipt of those payments. So that s big piece of it. Williston is also a big piece of it. Our view of the Williston is, is that a 19 – 2019 could be even as good as 2018 was, if not better, if we hold the obviously some level $60-ish type crude oil prices. We got a pretty well – a pretty big backlog of activity in the Williston that we feel comfortable about. And then the Utica I know – I know the Utica disappointed some people from this announcement because of the DPPO, but the Utica is still going to be up probably in the mid upper teens as far as growth next year for us. So it’s, it’s still growing pretty significantly. Again, the MLP is getting the benefit of not having to pay as much. And I will tell you, given what we’re seeing the growth beyond 2019, now that starts to come into the picture with our customers. We’re pretty – we’re pretty excited about that growth. So those are the three areas. What’s the headwinds for us? I mentioned one, Western Colorado, we’re seeing a tough market out there given gas basis – again get pushed back up from Waha into that area. And the Barnett for us is a flat to slightly declining asset. So those two are probably headwinds for us that we are battling against. So the Marcellus is the other one, although that’s a lower margin business, we expect to see declines there through the year and then we are, do believe there’s going to be pretty good drilling and growth in the Marcellus probably towards the end of 2019. So it’s not going to contribute much to 2019, so that’s another. So they’re smaller headwind for us too. So that’s where we are. You throw all those into the black box and you’re going to get something north of 10% growth in. We think that’s good. We think that’s a strong idea. If I tell you, if I could sign up for that, over the next three to five years, double digit growth every year if I do it today.

[Kyle Mayfrom:]

All right, sounds good. Thanks for the color.

[Steve Newby:]

Yes. Thank you.

[Operator:]

I will now turn the call over to Steve Newby for closing comments.

[Steve Newby:]

I think we have one more question. Operator?

[Operator:]

[Operator Instructions] And we do have a question online, and that question comes from Elvira Scotto from RBC. Please go ahead.

[Elvira Scotto:]

Just one follow-up question for me. In terms of that growth outlook that you have. What sort of commodity price expectation do you have embedded in that growth outlook for 2019? Sorry.

[Steve Newby:]

Yes, I’d say we use the strip. So think of strip pricing is as, as what’s embedded in that. As you know, we’re not – we’re not a very sensitive directly to commodity prices. So it’s more of a, how it impacts drilling and completion activity, and a lot of this is set up through what’s going on right now, obviously in the fourth quarter, just give the cycle of completion. So rig activity going on in our areas right now really, really helps solidify 2019 view for us. But I think answered your question directly, I’d use strip pricing.

[Elvira Scotto:]

Got it. Great. And then just one last one. Can you just help us understand a little bit about the dynamics that are happening and you talked about this a little bit but maybe a little, a little more detail around – what’s happening at SMU and then how that benefits Ohio Gathering, and you know, what sort of trajectory – you said Utica is going to be up about 15% I guess. But what, what are the trajectories and how you see those two evolving in 2019 and then actually even beyond, because I think you’re still very bullish on all of it. I’m assuming?

[Steve Newby:]

We are – yes. So I want to – yes it’s a great question. I’m actually glad you asked it. So both are going to be up, so there’s not one carrying the other. We have one of our main anchor customers in our dry gas area, drilling and completing wells right now and expect it to continue that throughout 2019. And that’s a set plan that was put in place this past summer. It’s going to benefit us not just 2019 – well into beyond 2019. Those are big wells, we’re getting impacted right now. We did in the third quarter by that customer bringing off pads to complete – your own complete wells. So it’s a little lumpy, when that goes on. But it’s going to be consistent, in a pretty consistent ramp. And it’s all at SMU on existing pads, so there’s no CapEx associated with that. What we had in the third quarter as we had a, we anticipated our – one of our other big customer at SMU to begin drilling and completing as well. That was going to hit us in the first half of – the volume is going to hit us in the first half of 2019. What they decided to do is actually given, given current liquids pricing, which is very strong. They decided to drill focus to have more heavily on the wet gas window in the condensate window of the Utica. Which all by the way, we also have exposure there through OGC. So it’s benefiting us at OGC. We only own 40% of that system versus 100%. So there is a movement of cash flow. But again, the MLP isn’t exposed to that. They’re going to pay a lot less for that asset because of that movement. And so that’s what’s going on, what we are seeing longer-term, I mentioned it in the dry gas window, that customer who’s moved to the wet gas window is expecting to come back to the dry gas window as well. It’s going to be beyond 2019. And so perversely, that benefits the MLP is they’re not going to have to pay for the asset and the DPPO. So we are expecting with our two customers, they are pretty significant growth beyond 2019 in the dry gas window. And then that customer is drilling I think running three or four rigs, three rigs right now in the wet gas window of OGC and expect it to continue if not increase activity there. So we’re expecting volume growth in the Utica overall. We’re more bullish right now, than we’ve been in quite some time over the longer term. And I know it’s lumpy, and it showed up in the different payment, but we’re seeing pretty, pretty – some pretty significant activity and I want to stress even in 2019 for us, we expected to use could it be up significantly. So hopefully that gives you, gives you more color around it.

[Elvira Scotto:]

Yes. That’s very helpful. Thank you very much.

[Steve Newby:]

So I think that did on the questions operator. So, I’ll just wish everyone a happy early Veteran’s Day, and have a good weekend. And please follow-up with us, if as you have further questions. Thank you.

[Operator:]

Thank you. Ladies and gentlemen, this concludes today’s conference. Thank you for participating and you may now disconnect.