Summit Midstream Partners, LP
Q1 2017 Earnings Call Transcript

Published: 5 May 2017

[Operator:]

Welcome to the Q1 2017 Summit Midstream Partners, LP Earnings Conference Call. My name is Nicole and I’ll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] Please note that this conference is being recorded. I’ll now turn the call over to Marc Stratton. Mr. Stratton, you may begin.

[Marc Stratton:]

Thanks operator, and good morning everyone. Thank you for joining us today to discuss our financial and operating results for the first 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 of such expectations will prove to be correct. Please see our 2016 Annual Report on Form 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.

[Steve Newby:]

Thanks Mark, good morning everyone and thanks for joining us on the call this morning. As usual I'll begin with a few comments on the quarter and then I'll turn it over to Matt for more detail on our quarterly financial results. I’ll then wrap up by discussing our outlook for the balance of the year. Yesterday we announced our first quarter of 2017 financial results which included $71.4 million of adjusted EBITDA, $53 million of distributable cash flow and quarterly distribution coverage ratio of 1.19 times. Based on our quarterly distribution of $0.575 per unit. Consistent with our expectations in full-year 2017 financial guidance, adjusted EBITDA was up 2% year over year and down 1.8% from the fourth quarter of ’16. Distributable cash flow was up 2.7% year over year and flat with the prior quarter. Before I turn the discussion towards volume throughput and segment performance, I do think it's worth mentioning that we successfully accessed the capital markets in the first quarter through the issuance of a new $500 million series of 8-year senior notes at a coupon of 5.75%. The net proceeds from this transaction were used to tender and redeem all $300 million of our 7.5% notes originally due in 2021 and pay fees and related expenses. We also termed out $172 million of revolver borrowings. We view this transaction as another opportunistic step to incrementally position the balance sheet and improve our liquidity position which now stands at more than $775 million and prepare for the deferred payment in 2020. Turning the volumes, in past calls we’ve discussed the timing lag between reactivity and associated volume flows on our gathering systems. But to reiterate prior commentary, the trough in rig activity for us it was experienced across our asset footprint in the third quarter of 2016. And that negatively impacted our fourth quarter of ’16 results and the first quarter of ’17 financial results and it will spill over some into the early parts of the second quarter of ’17 performance. With that said we are very encouraged by the significant increase in rig activity across our gathering footprints, which is more than tripled in the course of ’17 and is expected to drive volume and adjusted EBITDA growth beginning in the second half of 2017. Our natural gas volume showed nice growth in the first quarter with total system volumes of 1.63 BCF a day which represents an increase of 6.8% over the first quarter of ‘16 and 8.2% over the fourth quarter of ’16. As a reminder these figures exclude our 40% share of high gathering volumes which is reported separately. Bright spots for the quarter include our Marcellus segment, which volumes increased 16% quarter over quarter as well as our operated dry gas Utica system, Summit Utica had a very strong 30% increase in volumes over the fourth quarter of ’16. These two gathering system served to offset a 9% decline quarter over quarter in our volumes at the Ohio gathering JV which was the result of natural declines from wells previously connected. In March of this year OGC commissioned a new dry gas compressor station for anchor customer. This station will facilitate higher dry gas volumes and carry within an incremental compression fee beginning in our second quarter of 2017 results. Also in late March, we commissioned a gathering and compression project for one of our customers with acreage adjacent to our Summit Utica system that was capacity constrained on a competing gathering system. We're seeing a fairly substantial uptick in volumes associated with this project. For point of reference, Summit Utica is currently gathering more than 400 million cubic feet a day which compares to an average of 211 million cubic feet in the fourth quarter and 275 million cubic feet in the first quarter. We currently have five rigs running behind our OGC system and completion crews are continuing to work on new wells behind our Summit Utica system. We anticipate our customers will further increase rig activity behind these systems in the next few months. This activity should provide continued strong natural gas volume growth for SMLP in the immediate term. We expect fourth quarter of 2017 completions to ramp up on both systems as producers are currently preparing for additional longhaul take away pipeline capacity coming online that will tighten basis differentials and improve producer returns. Our liquids gathering business which accounts for about 20% of our adjusted EBITDA saw volumes average over 76,000 barrels a day in the first quarter which was 7.2% below the fourth quarter of ’16. First quarter of ‘17 volumes were affected by several factors with the biggest one being the low drilling activity in the fourth quarter of ‘16 which led to no first quarter of ‘17 completions. Other factors include the severe winter weather in North Dakota together with ongoing drilling and completion activity in our service area that requires certain existing production to be taken offline for a period of time during the quarter. We expect those well to be brought back online during the second quarter of ‘17. Similar to other areas we have seen an increase in drilling activity in the Williston and we are expecting completion activity to pick up beginning in the second quarter of ‘17 and accelerate throughout the balance of the year in our area. We also expect to complete our connection to Dakota Access this month and should begin offering this delivery point to our producers by the end of the second quarter of ‘17. We are already seeing a positive impact in the basin from Dapple [ph] in terms of compressing basis differentials and we expect the improved basis to continue as Dapple ramps up. As I mentioned earlier we're excited about the rig activity across our gathering footprints which represents a key catalyst to our growth in the back half of ’17. In the Barnett while the entire basin had limited rig activity over the past three years, we've had four of our five top customers acreage trade hands in ’16. And as of early April of this year our customers are now running two drilling rigs and two workover rigs behind our system. We expect this activity to lead to incremental volumes in the second half of this year. Our customers are operating five drilling rigs currently in the Utica and had anywhere from four to seven rigs operating during the first quarter. Similarly in the Williston, we've seen rig activity increase with three rigs currently behind our Polar & Divide system. This activity is incremental to the 40 plus drilled but uncompleted wells already behind our Williston system and represents a meaningful catalyst for future growth. Finally, we continue to see encouraging rig activity in Piceance and DJ Basin segment, where volumes have stabilized in the 615 million a day area, which is up over 7% from the first quarter of ’16, despite a continued lack of drilling from our anchor customer there. In this segment we currently have three rigs working and an expectation that our customers will add two more rigs in the area by the end of the second quarter. Yesterday, we reaffirmed our 2017 financial guidance which is unchanged from our initial release on January 26 of this year. As previously mentioned, we expect strengthening volume throughput and financial results throughout the course of the year with a fourth quarter 2017 annualized adjusted EBITDA run rate of between 325 million and 345 million representing a 12% to 19% increase over annualized fourth quarter of 2016 run rate. So with that I'll turn it over to Matt to review the quarter in more detail.

[Matt Harrison:]

Great, thanks Steve. Summit reported a net loss of 600,000 for the first quarter of 2017 compared to a net loss of 3.7 million in the first quarter of 2016. Net loss in the first quarter of 2017 included 22 million of early extinguishment of debt expenses associated with our first quarter 2017 tender and redemption of all 300 million of our 7.5% senior notes due in 2021. The first quarter of ‘17 also included 20.9 million of non-cash deferred purchase price obligation expense. In conjunction with 26 Drop Down transaction, we recognized a 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 our acquisition of 2016 Drop Down assets. We discount the estimated remaining consideration on the balance sheet and recognize the change in 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 value of the deferred purchase price obligation. Net loss the first quarter of 2017 also included recognition of 37.7 million of noncash gathering revenue related to a certain Williston Basin customer which was previously recorded on SMLP’s balance sheet as deferred revenue. This noncash recognition of previously recorded deferred revenue had no impact on our adjusted EBITDA or DCF calculations. Net loss for the first quarter of ‘17 also included the recognition of $2.6 million business interruption insurance recovery related to a 2015 claim at our Williston Basin segment. Net loss for the first quarter of 2016 included 1.2 million of transaction costs related to the 2016 dropdown transaction and 7.5 million of non-cash deferred purchase price obligation expense. Adjusted EBITDA for the first quarter 2017 totaled 71.4 million compared to 70 million for the first quarter of 2016. The 1.4 million increase in adjusted EBITDA was primarily due to the increase in natural gas volumes throughput on our Summit Utica system and Piceance/DJ Basin basins segment. These increases were partially offset by natural gas volume declines on Ohio gathering and the Barnett system and by lower liquids and natural gas throughput on our Williston Basin segment. Also adjusted EBITDA for the first quarter of 2017 was positively impacted by the recognition of a 2.6 million business interruption insurance recovery at our Williston Basin segment. G&A increased by approximately 1.3 million in the first quarter of ‘17 compared to ’16, primarily due to increases in salaries and benefits expense. The first quarter of 2016 included approximately 1.2 million of right-of-way repair operating expenses related to our Marcellus segment. Adjusted EBITDA in the first quarter of 2017 included approximately 16.8 million related to MVC mechanisms for natural gas gathering and crude oil transportation agreements. Additional detail regarding MVC is included in the first quarter earnings release. Distributable cash flow totaled 53 million in the first quarter, which implies that distribution coverage ratio of 1.19 times relative to the first quarter distribution of $0.575 per common unit to be paid on May 15. CapEx for the first quarter totaled 14.4 million of which 2.2 million was classified as maintenance CapEx. Also the partnership made approximately 4.9 million of capital contributions related to the Ohio gathering in the first quarter. We had 475 million outstanding under 1.25 billion revolving credit facility at March 31 and 775 million of available borrowing capacity. Total leverage as of March 31 was 4.35 times. On February 8, we issued 500 million of senior unsecured notes due 2025 with the coupon of 5.75%. The net proceeds from this offering were used to redeem the 7.5% 300 million senior unsecured notes due in 2021 including associated tender and call premiums, transaction expenses into partially repay the revolving credit facility. Summit also reaffirmed its 2017 financial guidance. We expect 2017 adjusted EBITDA to range from 295 million to 315 million. We expect quarterly adjusted EBITDA to increase throughout 2017 and we are guiding to an annualized fourth quarter 2017 adjusted EBITDA run rate of between 325 million and 345 million. We expect distribution coverage for the full year to average between 1.15 times to 1.25 times. With that I’ll turn the call back over to Steve.

[Steve Newby:]

Thanks Matt. As we mentioned in the press release last night we have seen a firming of producer sentiment so far this year, which is leading to not only an increase in rig deployments but also an uptick in commercial discussions and opportunities. We’re very levered to addition infill drilling in our existing footprints given the capacity expansions we've completed over the past three years. But we are also actively reviewing several new expansions of certain of our systems to accommodate for the increased activity going into 2018. We continue to evaluate resuming distribution growth in the back half of ’17. As we've said before we want to see volume growth materialize which based on current rig activity appears to be occurring and is setting us up for significant growth in the fourth quarter of this year and into 2018. The timing of well completion activity during the second half of 2017 will be critical to our calendar year performance. As such we think a better measure of growth coming out of this commodity price downturn will be sequential quarterly growth particularly in the fourth quarter of this year. We believe producers mainly on the natural gas side will be planning their completions for both the winter of ‘17 and also new longhaul takeaway capacity that's coming online in certain of our key bases. So in summary we are pleased with our first quarter, it was in line with our internal expectations, our customers are ramping their drilling and completion activity and as a result we remain optimistic on the remainder of 2017. So with that I'll turn it over to the operator to open it up for questions.

[Operator:]

[Operator Instructions] And our first question comes from Kristina Kazarian from Deutsche Bank. Your line is open ma'am.

[Kristina Kazarian:]

Thanks for the details on expectations around the cadence of volume ramp. Could you maybe provide a bit more color when we're thinking about the Utica in terms of how many rigs you guys are thinking for over the next nine to 12 twelve months might come into visibility. And also how you’re thinking about how long it takes to sort of rollover and then taking it back to your system. Do you need to ramp CapEx to accommodate these sort of things or how you think about flexing system capacity.

[Steve Newby:]

Yeah Kristina, it’s Steve. A lot in that question, I'll try to take rig count first, I think we had anywhere from four to seven rigs in the first quarter working in the area. I think we plan on seeing that level of activity through the balance of the year. It will move around a little bit as folks bring things in and out. But I think our expectation is in that range. As far as filling Rover, I mean, we're just one area of it, there's a lot of areas of it that will be - you get the benefit of gas flows Rover. I think it is a big event for certain of our customers it's an even bigger event. I think you're seeing a pretty big push by certain folks particularly in the dry gas area because those are the biggest volume areas and so to fill their capacity. But I think overall it will it's going to be we believe it's going to be positive if nothing else the bases in the area as well, so just to give you a point of reference, we had customers last fall selling gas at $0.70 when hub was obviously north of 3. So we think that hopefully will - those days are past us. So to help in that respect as well too, as far as the timing to fill Rover, I’m probably not the best person to answer that one.

[Matt Harrison:]

I don’t remember your third question, Kristina.

[Steve Newby:]

Yeah sorry, did I - I may have missed one.

[Kristina Kazarian:]

And I’ve been asking everybody on Rover, so don’t worry, it’s not just you, time for flexing system capacity to meet.

[Steve Newby:]

Yeah, so I think it depends on the system. I think at OG, in our JV, we did that and it came on in the first quarter. We brought on a big dry gas compressor station. And I think we're well set on OGC. I think we'll be looking at additional compressor expansions probably more in the back half and into ’18 in that area. As we still - we expect volumes to ramp pretty significantly into ‘18 there at OGC. I think at SMU, our 100% on system. We are well set, we brought on what we call our TPL7 project, we brought it on late in the first quarter early second quarter that's what we referenced in my comments. That was a compressor station expansion. I think we're well set there. I do think we're well set there for some period of time and we start to look at - and are starting to look at ideas to expand that whole system as we are filling up fairly quickly there. So we’re – you’d probably heard my commentary we're north of 400 million a day to day. That system is a 500 to 550 capacity system. So it’s filling up pretty quickly. So that is an area where I think we're going to start, we already are starting to look at potential expansion. I would tell you most of that CapEx would probably be into ‘18.

[Kristina Kazarian:]

And then last one from me, is when I’m thinking about the Rockies, you guys had a good quarter on the PE side. Can you maybe talk about the potential for in kind of sale of their acreage and what their read through might mean for you guys if this did happen.

[Steve Newby:]

Yes. I probably need to be careful and cautious on speaking about one of our customers is going to sell their acreage. But I think it wouldn’t - I would say it wouldn't surprise us just given their you know some of their public commentary about where they're focused on. I think it's – look, it's generally - EnCana hasn’t drilled well in three plus years. And so an acreage trade there I think in general is very positive to us. We have north of 100,000 acres dedicated to us from them. We have a big system in place. So we don't have to - it's not somebody starts really drilling, it's not a lot of incremental capital for us. Depending on where they start drilling, which we think we have an idea of a new owner where they probably would focus on, I think it's going to be incremental versus just taking care of amends. And so overall, acreage trades in general for us are positive. So I think that one would be given the situation around them and their lack of activity would be incrementally pretty positive for us.

[Operator:]

And our next question comes from Gabe Moreen from Bank of America Merrill Lynch. Your line is open.

[Gabe Moreen:]

A little opening question, I think in the press release and your comments, Steve, you mentioned, new projects and I think even new basins. Can you just about the new basin aspect of that and also to what extent, given cost of capital, balance sheet, you might be able to rely on your sponsor for help here?

[Steve Newby:]

Yeah. I think in general, we've seen a firming somewhat of the markets. Yesterday wasn't real encouraging, but in general firming, I mean I think in general, producers are much more comfortable than a year ago of operating in this kind of commodity price environment. That’s probably as important gotten across the line and so forth. They've also gotten the balance sheet in line. So what it does is it's making them feel more comfortable and then in turn we're having more discussions as they ramp activity about activity with them in existing areas and then RMO, our focus has been, and I think we've said this pretty clearly to the folks on the phone is really looking at new areas with an existing customer that we already service as they move to a new area or do something in a new area. So I think that's going to be our focus. I think it's going to be tough, given current M&A environment and multiples to be, it’s going to be tough for us to play in that arena because at the end of the day, the way we look at it is although certain basins are real exciting for growth, you still got to be able to make money in them. And so that's what we're supposed to do to create value. So it's tougher also at some of the levels to see how that would work for at least Summit. So I think what gave -- what I was alluding to is conversations going on about us partnering with and working with some of our customers as they look at other areas. Sponsor, yes. On sponsor, yes, I mean I think we continuously have questions or commentary with our -- not questions with our sponsor about ways we can work with them going forward. They have a lot of capital and there could be potential JV type situations or things like that. We don't see ourselves as necessarily capital constrained if the right -- for the right transaction in general. I think it can be -- the right transactions can be structured such that it’s our value creating gold. They'll be able to get financing and yes, energy cattle is probably one of the sources, primary sources for that if we need it.

[Gabe Moreen:]

Thanks, Steve. And kind of a generic question, but in terms of the interplay between the yes or no on distribution increases this year. I mean is it just kind of TBD in terms of commodity price environment and I guess how you’re thinking about that?

[Steve Newby:]

Yeah. I think we're going to probably be behind the volumes versus in front of them if that makes sense. I think we really want to see the volume ramp occur before we get out over on distribution growth. I think we've been consistent in saying that we want to see, yes, we've seen an increase of rig activity, significant increase in rig activity in our system, but I think we want to see it turn into volumes, because timing is critical on these things and we don't control that. Our producer or customers do. And so Dave, I would say, we want to see it materialize. We've seen good indications through the first quarter of this year and through where we sit here today, early part of May but we got to see it turn into volumes and I don't think we need to be ahead of it. I will say folks as of right now are getting paid about 10% on our units to wait. So they are making a pretty and that's pretty secure. And so I think we're making a fairly nice return. So I think we're going to swirl away to those materialize and make a decision, but our thought process is by the end of the year, we should see it materialize.

[Operator:]

And our next question comes from John Edwards from Credit Suisse.

[John Edwards:]

I just wanted to make sure I heard correctly in your prepared remarks that Utica volumes are running around 400 versus the 275 you reported. Did I hear that right?

[Steve Newby:]

That's right John. So that's on our 100% owned system, which we call Summit Utica, SMU, Summit Midstream Utica. And that's largely due to the project we brought on at the end of the first quarter. We announced it last, I think it was last fall, right. And we brought it on this quarter and it quickly ramped up. So that’s a project that under capacity project and a competitor’s system adjacent to Summit Utica.

[John Edwards:]

Okay. And so then the rate on those volumes and how should we think about the EBITDA contribution?

[Steve Newby:]

Yes. So I don't want to give rates, but I'll give you an idea. So it’s a, what we call, a high pressure service and we're de-hying the gas, some of the gas as well too. So we're not wellhead gathering there. We're providing compression and dehydration and interconnect ability. So it's similar, I would say when you think about it, think about the service similar to our Marcellus Service Mountaineer.

[John Edwards:]

Okay. So in terms of how we should be thinking about the EBITDA contribution?

[Steve Newby:]

Yes. It's lower margin business than our wellhead gathering business. But I would say very incremental related to our CapEx spend.

[Matt Harrison:]

And very comparable to Mountaineer for the incremental volumes.

[John Edwards:]

Okay. All right. That's helpful. And just on the, I guess, on the year-over-year drop in the Marcellus volumes, I know you made some comments there, any other color you can provide to us on that?

[Steve Newby:]

No. We had an increase quarter-over-quarter, pretty nice. We, in the first quarter of last year, we had a pop because a longhaul project came online late in the fourth quarter, I believe of ’15 and so the comparable is probably a little messy on those two quarters. We still have drill locally ducts behind the system to bring on, I will remind everyone we bring the majority of our gas on that system from Antero Midstream and so they still have a fair amount of ducts docs to bring on as well too. So that's probably about the only color I can.

[Matt Harrison:]

We peaked in the first quarter of ’16 and so we've been declining throughout the year and then bringing on some more wells now here in the fourth and first quarters.

[Steve Newby:]

I would tell you that theme also relates to our liquids business too. It's just, it's not a tough comparison, but we peaked on our liquids business in the first quarter of ’16 also. So when you go year-over-year, you're looking at where we peaked as well in the first quarter and then through my commentary, you probably picked up, we troughed as far as rig count goes in the third quarter. So with the lag that hits us particularly hard in this quarter.

[John Edwards:]

Okay. That makes sense. And then just last one for me, just any update on your thoughts on the status of the deferred payment financing, how you're thinking about that?

[Steve Newby:]

Yeah. I’ll let Matt take that one.

[Matt Harrison:]

Yeah. Pretty -- it really hasn't changed since closing the transaction last March. We've kind of been opportunistically picking our spots, did an equity deal, $125 million equity deal in September. In February, we replaced 300 million of 7.5% 2021 notes with 500 million of 5.75% 2025 notes. So we currently have 775 million of liquidity under our revolver, coverage 1.19, leverage 4.35 and we feel, given the current cash flow contribution of these dropdown assets, we feel we're in a good spot relative to the prefunding plan. But as we've said before, we're an opportunist access to equity and debt capital markets over the next couple few years. We obviously have an ATM program that we could -- that we haven't used. We used slightly in the first quarter just to kind of make sure it works. You'll see that in our first quarter Q. But again to kind of repeat myself, when we settle that, we’ll be four times levered and at least 1.1 times covered.

[Operator:]

[Operator Instructions] Our next question comes from Elvira Scotto from RBC Capital Markets. Your line is open.

[Elvira Scotto:]

Just a couple of quick ones for me. One, did you quantify the impact of the severe weather to your operations in the Williston?

[Steve Newby:]

We didn’t, but I’ll give you a little color around it. For us, the weather affected the gas side probably more so than the crude side. I think it affected both, but I would tell you I think the gas side a little bit more and that's just, not going into too much in the weeds, that's just operationally how the systems are different and -- what we have to do on the gas side in pegging and things like that. So I would tell you it definitely affected us on the gas side. We've seen a rebound, that’s here at the end of the first quarter into second on gas volumes for sure and so that's probably the biggest. On the liquids side, I won’t sugarcoat it, the biggest impact to us was just the lack of the lower pace of drilling and completions for sure in the first quarter. So weather did affect us some, but not as much on the gas side I would say as on the gas side.

[Elvira Scotto:]

Okay, great. That's helpful. And then. My other question is really just maybe a little more color or commentary around your comments about being encouraged by some of the commercial activity that you're seeing and potentially expanding existing footprint but into other basins. Can you talk a little bit about maybe where you're considering expansions or maybe where you are in conversations with customers and if we could hear anything you think in the near term?

[Steve Newby:]

How do I answer that one? I would say -- I'll reiterate we're looking at having very detailed discussions with existing customers to service their needs as they look and are active in other areas. Where those areas are, I think we have 50 plus percent of the rig count working in 20 counties in North America. Right now, it’s hard to figure out sort of some of the areas we're looking at because we got a gas in crude oil and so we have to be that where activity is. So that probably gives you a good indication of some of the areas we're looking at. Where we are in status, you never -- I never want to get out too far and say, okay, I've seen some others say, when they're going to be announcing stuff and they’d be disappointed if they didn't. I would not say that because it's the commercial discussions, we’re in detailed ones on new areas, we’re in detailed discussions on our existing areas. We have some -- we're going to have some capacity constraints, given the pace of activity in some of our areas and so we're having discussions around expanding new areas as well too. We'll keep you posted and we tend to not get too far in front of these things as you know and we’ll announce them when we actually have ink dried on the paper.

[Matt Harrison:]

I would just add though, our current guidance does not include any of these commercial opportunities. CapEx or EBITDA.

[Operator:]

[Operator Instructions] Our next question comes from Tristan Richardson from SunTrust. Your line is open, Tristan.

[Tristan Richardson:]

Just a quick clarifying question, just on Larew, you talked in the prepared remarks and in the release about the additional compression fee that comes from bringing Larew on. I mean is that for a portion of OGC's volumes or will that incremental fee apply to all volumes that you will report for OGC?

[Steve Newby:]

It’s a portion Tristan. It's related to our dry gas area that we service for OGC. I would say it’s in the neighborhood for 20% to 25% of our volumes for that on OGC.

[Tristan Richardson:]

Okay. Great. That's really helpful. And then I guess also one on the SMU side, as you think about potential ways to expand capacity and you talked about sort of, that spend could come in ’18, I mean is it a situation where you can scale up with the small to modest type CapEx, the additional compressor expansions, et cetera or do you start looking at more -- larger projects to meaningfully expand capacity?

[Steve Newby:]

Yeah. It’s a great question. It's very good news for us. I think what we think about there is really in the station, in the discharge from downstream from the station. So it's more adding compression and adding residue lines to the larger interconnects, Ohio River Rover, things like that. We're not talking about huge incremental dollars. We have the infrastructure in place. It's a matter of looping lines and adding additional compression. We do not have -- we have not added yet compression for our anchor customer at SMU. The compression we added that I mentioned in the first quarter that came online was for the TPL7 project. We've yet to add for our wellhead gathering, because those wells are so strong, they just don't need it yet. And so that will occur. We will add compression. We've already built the stations to do that. We just got a slot compression in there. It will be incremental. We get an incremental fee for it and so it's known and I think that’s come in, but also what’s come in is the pace of activity and volumes coming on that system, we have to start looking at increase in the overall capacity of the system and it will be within the stations in the residue lines.

[Tristan Richardson:]

That's great. And then with floor connects in the first quarter, you may be trending below sort of what you were for the full year for ’16, but obviously you guys have talked about sort of increasing activity in the second half. I mean directionally do you see connects on Utica higher than in ’16?

[Steve Newby:]

Yeah. Just Matt was making the point. The well’s IP here between 10 million to 20 million a day. They’re big wells. So I would say on well connect direction, it’s tough to -- my guess is they won't be as high as ‘16. But I do think we’ll have increased activity by the end of the year and I actually think we're going to have another one of our big customers start to drill the area that they haven't drilled this area yet. They will or going to or planning to in the second half the year and that will lead to significant well connects in the first half of ’18 as well too and that's why capacity is on our mind greatly.

[Tristan Richardson:]

Okay. That's helpful. And then I guess just last one for me is more clarifying in the prepared comments, you talked about the Piceance and the Barnett and then you made mention of two rigs expected to be added in the second half. Was that behind the Piceance system or was that DFW?

[Steve Newby:]

Yeah. So I’ll clarify. So we have four rigs working in the Barnett, two drilling rigs and two workover rigs currently. So there's activity there. I think we talked -- have talked in last quarter about the workover activity in the Barnett by our largest customer there. It is ongoing. I think it's making an impact there as well too and we also have two rigs drilling, new wells in the Barnett. In the Piceance, to clarify what we said is two rig adds through the back half of the -- two additional rigs coming in. Our line of sight is coming in in the back half of the year to drill and obviously the drill, the complete cycle in the Piceance is shorter than it is in a place like the Utica or otherwise. I think they get a well down somewhere in the neighborhood of 7 to 10 days in the Piceance.

[Tristan Richardson:]

Okay. I was actually -- I thought it was a positive surprise to see the activity in the Marcellus and so kind of -- I know you touched on this with an earlier question, but any just general commentary you can give on either rigs behind your acreage there or sort of inventory level of ducts currently. I think you guys provided that number maybe in the past, but

[Steve Newby:]

Yeah. We have 18 ducts in the Marcellus. So we would expect that to be, that's what that we believe they're going to focus on completing through the rest of the ‘17. I don't think there's any rigs working behind the Marcellus right -- our system right now. So it's a duct story for the rest of ’17 I think. I'm not sure we have line of sight whether they bring one back in or not.

[Operator:]

We have no further questions at this time.

[Steve Newby:]

Okay. I appreciate it. Everybody have a good weekend. Thank you.

[Operator:]

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.