Summit Midstream Partners LP (SMLP) 2017 Q1 法說會逐字稿

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. (Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to 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 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 that 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.

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 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 a quarterly distribution coverage ratio of 1.19x, based on our quarterly distribution of $0.575 per unit. Consistent with our expectations and 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 to 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 in payee 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 to volumes. In past calls, we've discussed the timing lag between rig activity and associated volume flows in our gathering systems. But to reiterate prior commentary, a trough in rig activity for us was experienced across our asset footprint in the third quarter of 2016. And that negatively impacted our fourth quarter '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 has more than tripled during the course of '17 and is expected to drive volume and adjusted EBITDA growth beginning in the second half of 2017.

Our natural gas volumes 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 an increase of 8.2% over the fourth quarter of '16. As a reminder, these figures exclude our 40% share of Ohio Gathering volumes, which is reported separately. Bright spots for the quarter include our Marcellus segment, in which volumes increased 16% quarter-over-quarter as well as our operated dry gas Utica system, Summit Utica, which had a very strong 30% increase in volumes over the fourth quarter of '16. These 2 gathering systems serve to offset a 9% decline quarter-over-quarter on 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 our 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 5 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 long-haul takeaway pipeline capacity coming online that will tighten basis differentials and improved producing 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 in our 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 required certain existing production to be taken off-line for a period of time during the quarter. We expect those wells 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 it 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 DAPL, in terms of compressing basis differentials and we expect the improved basis to continue as DAPL ramps up. As I mentioned earlier, we are excited about the rigs 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 in the past 3 years, we had 4 of our 5 top customers acreage trade hands in '16, and as of early April of this year, our customers are now running 2 drilling rigs and 2 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 5 drilling rigs currently in the Utica and had anywhere from 4 to 7 rigs operating during the first quarter. Similarly, in the Williston, we've seen rig activity increase with 3 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 our Piceance and DJ basins 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 3 rigs working in an expectation that our customers will add 2 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 in 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 our annualized fourth quarter of 2016 run rate.

So with that, I'll turn it over to Matt to review the quarter in more detail.

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 noncash deferred purchase price obligation expense.

In conjunction with the 26 drop-down transaction, we recognized a liability on our balance sheet for the deferred purchase price obligation to reflect the estimate of the remaining consideration to be paid in 2020 for our acquisition of the 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 in 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 a $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 cost related to the 2016 drop-down transaction and $7.5 million of noncash deferred purchase price obligation expense.

Adjusted EBITDA for the first quarter of 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 and volumes throughput on our Summit Utica system and Piceance/DJ 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 the $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 MVCs mechanisms for our natural gas gathering and crude oil transportation agreements. Additional detail regarding MVCs is included in the first quarter earnings release.

Distributable cash flow totaled $53 million in the first quarter, which implied a distribution coverage ratio of 1.19x 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.

With $475 million outstanding under our $1.25 billion revolving credit facility at March 31 and $775 million of available borrowing capacity, total leverage as of March 31 was 4.35x. On February 8, we issued $500 million of senior unsecured notes due 2025 with a 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 and to partially repay this 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're 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 1.15x to 1.25x.

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

Thanks, Matt. As we mentioned in the press release last night, we have seen a firming of producer sentiments 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 through additional infill drilling in our existing footprints given the capacity expansions we've completed over the past 3 years.

We were 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 step forward, we want to see volume growth materialize, which is based on current rig activity, appears to 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 long-haul takeaway capacity that's coming online in certain of our key basins.

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 Instructions) And our first question comes from Kristina Kazarian from Deutsche Bank.

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 Utica in terms of how many rigs you guys are thinking for over the next 12 -- 9 to 12 months might come into visibility? And also, how you are thinking about how long it takes to fill Rover and then taking it back to your system, you need to ramp CapEx to accommodate these sort of things? Or how do you think about flexing system capacity?

Kristine, it's Steve. A lot in that question. I'll try to take rig count first. I think, we've had -- we had anywhere from 4 to 7 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'll move around a little bit. (inaudible) 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 that will be -- get the benefit of gas closer to Rover. I think, it is a big event. For certain of our customers, it's a 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's going to be -- we believe, it's going to be positive, if nothing else the basis 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, that hopefully will -- those days are past us. So to help on that respect as well too. As far as the timing to fill Rover, I'm probably not the best person to answer that one.

I don't remember your third question, Kristine.

Yes. Sorry, I may have missed one.

I've been asking everybody about filling Rover, so don't worry, it's not just you. Timing for flexing system capacity to meet (inaudible)?

Yes. So I think, it depends on the system. I think at OGC in our JV, we did that and it came on in the first quarter. We brought 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 are 100% owned system. We are well set. We brought on a what we call our [TPS 7] project. We brought it on right 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 -- and are starting to look at ideas to expand that whole system as we are filling up fairly quickly there. So we're -- you probably heard my commentary, we're north of 400 million a day-to-day, that systems are 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.

Got it. And then last one for 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 -- and Encana sale of their acreage and what their read-through might mean for you guys, if this did happen?

Yes, I probably need to be careful and cautious on speaking about this, one of our customer's is going to sell their acreage. But I think it wouldn't -- I would say, it wouldn't surprise us just given their -- some of their public commentary about where they're focused on. I think, it's -- look, it's generally -- Encana hasn't drilled a well in 3-plus years. And so the acreage trade there I think, in general is very positive to us. We had 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 a -- if somebody starts 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 acres. 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.

And our next question comes from Gabriel Moreen from Bank of America Merrill Lynch.

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

Yes, I think in general we've seen a firming somewhat of the markets -- yesterday, it wasn't really encouraging. But in general a firming of it. And 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 getting the cost structures around and so forth. They're also getting their balance sheet in line. So what it does is it's making them feel more comfortable, and then in turn, we are having more discussions as they ramp activity about activity with them in existing areas. And then RMO, our focus has been -- I think, we said this pretty clearly to the folks on the phone is, 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 the 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 and because at the end of the day the way we look at it is although, certain basins are really exciting for growth, you still got to be able to make money in them. And so that's what we're supposed to do is create value. So it's tough for us with some of the levels to see how that would work for at least Summit. So I think, what Gabe -- 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.

Sponsors.

Sponsors, yes. Thanks, Matt. Sponsors, yes, I mean, I think, we continuously have questions or commentary with our -- not questions with our sponsor about ways that we can work with them going forward. They have a lot of capital and there could be potential JV-type situations and 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, that they're value creating that we'll be able to get financing. And yes, Energy Capital is probably one of the sources, primary sources for that if we needed.

Steven, 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?

I think, we're going to probably be behind the volumes versus in front of them, if that make 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, I mean, we want to see -- yes, we've seen an increase in rig activity, significant increase in [reactivating] 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, Gabe, I'd say, we want to see it materialize and 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've got to see a turn in the 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 weight. So it's -- they are making a pretty -- and that's pretty secure. And so I think we are making a fairly nice return. So I think we're going to wait till those materialize and make a decision. But our thought process is by the end of the year, we should see it materialize.

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

I just want to make sure I heard correctly in your prepared remarks that Utica volumes are running around 400 versus the 275 you reported, is that -- did I hear that, right?

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 bought out at the end of the first quarter. We announced it last -- I think, 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 competitor's system adjacent to Summit Utica.

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

Yes, 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 in that they're behind the gas, some of the gases well too. So it's -- 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 our service similar to our Marcellus service Mountaineer.

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

Yes, it's lower margin business in our wellhead gathering business. But I would say, very incremental related to our CapEx there related to it.

And very comparable to Mountaineer for the incremental volumes of the field set.

Yes.

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. And any other color you can provide to us on that?

No, it's -- we had an increase quarter-over-quarter pretty nice. We -- in first quarter of last year, we had a pop because long-haul project came online late in the fourth quarter, I believe of '15. And so the comparable is probably a little messy on those 2 quarters. We still have -- drill locally DUCs behind the systems to bring on. I will remind everyone, we bring the majority of our gas on, on that system from Antero Midstream. And so they still have a fair amount of DUCs to bring on as well to. So that's probably about the only color I can hit on it.

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

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 the rig counts goes in the third quarter. So with the lag that hits us, particularly hard in this quarter.

Okay. That make 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?

Yes, I'll let Matt take that one.

Yes, pretty -- it really hasn't changed. Since closing the transaction last March, we've kind of been opportunistic picking our spots, did equity deal, $125 million equity deal in September. On February, as you know, 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 given the current cash flow contribution of these drop-down assets, we feel we're in a good spot relative to the pre-funding plan. But as we've said before, we want to opportunistically access to equity and debt capital markets over the next couple of few years. We obviously have an ATM program 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 4x levered and at least 1.1x covered.

(Operator Instructions) Our next question comes from Elvira Scotto from RBC Capital Markets.

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

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 [weed], that's just operationally how the systems are different and how -- 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 as here at the end of the first quarter into second on gas volumes for sure. And so that's probably the biggest. On the liquid side, I'm not -- I wouldn't sugarcoat, the biggest impact to us was just the lack of 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.

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 extending 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?

Yes. How do I answer that one? We're cautious on that. I would say, I'll reiterate, we are looking at having a very detailed discussions with the existing customers to service their needs. They've been active in other areas. Where those areas are, I think we had 50-plus percent of the rig count working in 20 counties in North America. It's probably not hard to figure out sort of some of the areas we're looking at because we got the gas and 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 other say, when they're going to be announcing stuff and maybe disappointed if they didn't. I wouldn't -- I will not say that, because it's the commercial discussions very detailed ones on new areas were in detail discussions on our existing areas. We have some -- we're going to have some capacity constraints in the pace of activity in some of our areas. And so we are 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 (inaudible) and we actually have incremental drive on the paper.

I will just add though, our current guidance does not include any of these commercial opportunities.

I'd agree with that, yes.

In CapEx or EBITDA.

(Operator Instructions) Our final question -- our next question comes from Tristan Richardson from SunTrust.

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

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.

On OGC, yes.

Okay, great. That's really helpful. And then -- and I guess, also 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 -- you say, small to modest-type CapEx, the additional compressor expansion et cetera or do you start looking at more larger projects to meaningfully expand capacity thus far?

Yes. That's a great question. It's very good news for us, I think. What we think about there is really in the station and 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 4 of the [TPS 7] 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 to strap the compression in there. It will be incremental. We'll get an incremental fee for it. And so it's known. And I think that's coming. But also what's coming is, the pace of activity and volumes coming on that system. We have to start looking at increasing the overall capacity of the system and it will be within the stations in the [residue] lines.

That's great. And then, with 4 connects in the fourth 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?

I think, I mean, 4 connects is a lot of volume.

Yes, just Matt was making the point. [World's IP] here between 10 to 20 million a day. They are big wells. So I would say on well connect directions, it's tough to -- my guess, is they won't be as high as '16. But I do think, we'll have well connections with -- 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 and they haven't drilled this area yet. They will or going to or planning to in the second half of 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 minds greatly.

Okay. No, that's helpful. And then, I guess, just last one for me, the more clarifying. In the prepared comments, you talked about the Piceance and the Barnett. And then, you made -- mentioned the 2 rigs expected to be added in the second half. Was that behind the Piceance system or was that DFW?

Yes. So I'll clarify. So we have 2 -- we have 4 rigs working in the Barnett, 2 drilling rigs and 2 workover rigs currently. So there's activity there. I think we talked and have talked in the 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 2 rigs drilling new wells in the Barnett. In the Piceance, we want to clarify what we said, is 2 rig adds through the back half of the -- 2 additional rigs coming in. Our online site is coming in, in the back half of the year to drill. And obviously, the drill of the complete cycle in the Piceance is shorter than it is in a place like the Utica or otherwise. I think they're going to go down somewhere in the neighborhood of 7 to 10 days in the Piceance.

Okay, okay. She said, I was the final question, so I might just ask one more if -- well, I've got you, guys. 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, it was an earlier question. But any just general commentary you can give on either rigs behind your acreage there or sort of the inventory level of DUCs currently? I think you guys provided that number maybe in the past, but I don't know...

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

Is that it operator, as far queue?

We have no further questions at this time.

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

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