Summit Midstream Partners LP (SMLP) 2016 Q2 法說會逐字稿

Welcome to the second quarter 2016 Summit Midstream Partners LP earnings call. My name is Eric, and I will be 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 second quarter of 2016. If you don't already have a copy of our earnings release, please visit our website at www.summitmidstream.com where you will find it on the homepage or in the news section.

With me today to discuss our earnings is Steve Newby, our President Chief Executive Officer, and Matt Harrison, our Chief Financial Officer. Before we start I would 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 Please see our 2015 annual report on Form 10-K, as updated and superseded by our current report on form 8-K, which was filed with the SEC on June 6 2016, as well as our other SEC filings for a listing of factors that could cause actual results to differ materially from expected results.

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

With that, I will turn the call over to Steve Newby.

Thanks, Mark. Good morning everyone and thanks for joining us on the call today. I will begin with a few comments on the quarter, and then I'll turn it over to our CFO Matt Harrison for more detail on our quarterly financial results. I will then wrap up the discussion on our outlook for the balance of the year including our decision to increase the midpoint of our full-year 2016 adjusted EBITDA and distribution coverage financial guidance.

Yesterday we announced our second-quarter 2016 operating and financial results for SMLP. Overall it was another solid quarter particularly given the continuation of a challenging commodity price back drop. Adjusted EBITDA totaled $72.4 million for the second quarter, which was up 17% over the second quarter of 2015 and up 3.4% over the first quarter of 2016.

Adjusted distributable cash flow totaled $51.1 million for the quarter, which was up 11.9% over the second quarter of 2015, but down 3% over the first quarter of this year. The slight decrease in adjusted distributable cash flow quarter-over-quarter was primarily due to higher maintenance capital expenditures in the second quarter versus the first quarter. Just to point out the second and third quarters of the year are typically a higher period for us for maintenance capital expenditures than the first and fourth quarters given the weather.

In addition our second quarter cash interest expense was about $700,000 higher than the first-quarter, due to a full quarter of interest expense related to our $360 million borrowing in March, to fund an initial payment made on the 2016 drop-down assets. On July 21 we announced our second quarter 2016 distribution of $0.575 a unit, which was flat with the first-quarter and up 0.9% over the prior-year period. We'll pay the distribution on August 12.

This is the second consecutive quarter following our 2016 drop-down transaction, in which we have exceeded our distribution coverage target of 1.1 to 1.2 times. In fact we've covered the second quarter distribution of 1.25 times, and year-to-date we have covered the distribution at 1.27 times. Matt will discuss this further in his remarks, but, given our results through the first two quarters of 2016, and our firming outlook on the balance of the year, we are raising the midpoint of our adjusted EBITDA guidance to $280 million, with a new range of $270 million to $290 million.

We're also raising full year distribution coverage guidance from a prior range of 1.1 to 1.2 to a new range of 1.15 to 1.25. As I briefly referenced earlier during the first quarter of 2016 we dropped down all of the remaining operating assets from Summit Investments, SMLP, including both of our Utica shale assets, which include our 40% interest that we own in Ohio gathering alongside MPLX and EMG, and our wholly owned and operated Summit Utica dry gas gathering system.

The acquisition also included our interest in our Williston-based crude oil, natural gas and produced water gathering assets, as well as our social natural gas gathering and processing system located in the DJ Niobrara. To remind everyone the acquisition consideration was structured in a manner that allows us to 100% debt-finance $360 million initial payment, which represents a 4.5 times multiple of our $75 million to $85 million 2016 adjusted EBITDA guidance for these assets.

The balance of the purchase price, which we refer to as the deferred payment, will be paid in 2020 and will be based on a 6.5 times multiple of the average actual historical EBITDA in 2018, and 2019, from the acquired assets adjusted for cumulative CapEx and cumulative EBITDA during the deferral period. This deferred payment structure provides SMLP with a tremendous amount of free cash flow and distribution coverage that we are able to reinvest into our business.

The structure also includes embedded option value that allows us the ability to opportunistically choose how and when to finance the deferred payment, which isn't due until 2020. Until 2020 we have more than adequate liquidity to continue to fund all of our existing development plans. Operationally our systems gathered an average of 1.5 BCf a day of natural gas volumes in the second quarter, which excludes our 40% proportional share of Ohio Gathering volumes.

This amount was relatively flat to the first quarter. Just to remind everyone, approximately 70% of our expected 2016 adjusted EBITDA, which is primarily underpinned by fee-based gathering arrangements, will be generated from natural gas gathering versus approximately 30% from liquids.

Although given the high correlation between our unit price relative to crude oil prices, might infer the opposite. Nonetheless we expect that this ratio will increase over time as gas volumes from our Utica assets grow disproportionately higher versus our Williston assets. Our results primarily benefited from the continued volume growth across the recently acquired high growth Utica gathering systems.

Volumes in our Summit Utica system increased by more than 26% over the first quarter volumes to 167 million cubic feet a day, as a result of ongoing development of our system to connect consistent drilling and completion activities by our anchor customer. We exited the quarter with June volumes on the system approaching 200 million cubic feet a day, versus the second quarter average of 160 million cubic feet a day, and we have visibility towards additional completion across the system over the remainder of the third quarter.

In addition we are scheduled to bring on our third dehy station in the third quarter, which will increase our total capacity of Summit Utica to 450 million cubic feet a day. Our Ohio Gathering JV volumes averaged 937 million cubic feet a day in the quarter on an [eight eights] basis. This was up 5.5% over the first quarter of the year and 78% over the same period last year. This increase was primarily due to the release of shut in volumes from curtailment activities that occurred in the first quarter due to low natural gas price environment.

In addition we had 13 dry gas wells completed late in the first quarter, which helped increased volumes in the second quarter. As we stated during our first quarter call, we would expect the balance of the year slightly lower sequential volumes at Ohio gathering, given lower completion activity during the second quarter.

We expect completion activity to pick up during the third quarter, but we would anticipated it being in late in the third quarter before we see an impact. Interestingly given the outlook for improving NGL prices, we expect the higher level of completion activity to occur in the wet gas window.

The largest sequential quarterly volume decline the second quarter was associated with our Marcellus segment, which declined by 37 million cubic feet a day versus the first quarter of 2016. We estimate that approximate 20 million cubic feet of this decline was due to an operational issue with a third party takeaway pipeline, that affected the amount of gas that we could deliver to the Sherwood processing complex. We're happy to report that this issue was resolved in the early part of July and that volumes have quickly returned to levels that were experienced prior to the third-party operational issue.

Looking forward we still have visibility towards a sizable backlog of approximately 27 DUCs behind Summit's Mountaineer system. We expect a handful of these DUCs to be completed in late 2016, and the majority of these completions to be pushed to 2017.

In the Barnett our quarter volumes were flat compared to first-quarter, as completion activity during the quarter offset natural declines from older wells. We continue to benefit from our customer diversity in this area as certain of our 10 customers have been active throughout this cycle, which has largely offset volume declines from a couple of our larger customers.

To that and we visible towards an additional six wells, which are expected to come online in the fourth quarter of 2016 that have already been drilled on our system. We are also encouraged by some recent customer turnover on acreage located behind our gathering system.

There's a recent A&E transaction the first quarter related to approximate 10,000 acres on our AMI. We expect that this new privately held customer will begin drilling again in this area towards the back half of 2016 and into 2017.

Our final natural gas focus segment is the Piceance and DJ Basin, which consist of our legacy Western Colorado gathering and processing systems, and our new DJ Niobrara associated gas gathering and processing system. This is a segment that has experienced sequential volume declines for much of the past three years largely related to one producer, however, because of the highly contracted nature of the gathering system, our cash flow declines have largely been mitigated.

An interesting dynamic is occurring in the Piceance and DJ, in that now four of our six largest customers are owned by private equity groups that have limited drilling alternatives outside of this area. And over the last several months these companies have began to accelerate drilling and production plans and activities on acreage located behind our gathering systems. It's too early to call but we are becoming much more optimistic about the outlook for this segment and particularly the impact it may have on 2017.

Switching to our liquids business in the Williston, we saw our liquids volumes declined 9.5% over the first quarter, which included a slight increase in our produced water volumes that was offset by a decline in crude oil volumes. The crude oil volume decline was primarily driven by natural declines that occurred related to well completions made during the fourth quarter of 2015 in the first half of the year.

However, we were also affected by volume shut-ins as certain of our customers took down existing productions from wells located in the vicinity of ongoing completion activity. We are already seeing the benefit from these completion activities through the first half of the third quarter.

We estimate that our producers have approximately 60 DUCs on our crude oil system. In addition we continue to work to gain market share from trucks, particularly with regard to produced water volumes. This is an area that we may see increased volumes in the back half of 2016, despite flattening underlying crude oil volumes.

Looking forward we are working diligently to position our crude oil gathering system, which handles approximately 50,000 to 60,000 barrels a day of crude oil, to be a staging area for volumes delivered to a new large take away pipeline that is expected to be placed into service by the end of this year. Currently these crude oil volumes are being delivered to the Colt rail terminal and other pipeline interconnects that we currently have access to.

The new pipeline will not only be an important transportation option for future Bakken barrels, but will also allow us to earn incremental revenue on existing gathered volumes in our systems through our interconnect with the pipeline. One final note on our cost control initiatives before I turn it over to Matt, I would like to applaud our team for its continued focus on managing expenses while maintaining the safety and integrity of our gathering systems.

A statistic we monitor closely is our controllable OpEx per thousand cubic feet equivalent, and in the second quarter of 2016 this metric was the lowest it's been at SMLP in the past two years, and over 7% lower than what it was just one year ago. We will continue to focus closely on cost management in what is proving to be a longer cycle than many of us had originally anticipated.

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

Great. Thanks, Steve. SMLP reported a net loss of $50.6 million for the three months ended June 30, 2016, compared to a net loss of $2.4 million the second quarter of 2015. This includes an impairment charge of approximately $37.8 million net to SMLP associated with Ohio gathering's 23,000 barrels per day condensate stabilization facility, and approximately $17.5 million of deferred purchase price obligation expense.

In conjunction with the 2016 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 the acquisition of the 2016 drop-down assets. We discount the 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.

Adjusted EBITDA for the second quarter of 2016 was $72.4 million, compared to $61.9 million for the second quarter of 2015. The $10.5 million increase in adjusted EBITDA was primarily due to increased natural gas volume throughput on our Summit, Utica and Ohio gathering systems, and increased liquids volume throughput on our Williston Basin gathering systems.

These volume throughput increases were partially offset by a volume declines in our DFW midstream, Grand River and Mountaineer midstream systems in the second quarter of 2016, compared to 2015. Adjusted EBITDA in the second quarter of 2016 included approximately $16 million related to MVC mechanisms from our natural gas gathering and crude oil transportation agreements. Additional tabular detail regarding MVCs is included the second-quarter earnings release.

Adjusted distributable cash flow totaled $51.1 million in the second quarter of 2016. This implied a distribution coverage ratio of 1.25 times relative to the second quarter of 2016 distribution of $0.575 per limited partner unit to be paid on August 12. CapEx for the second quarter of 2016 totaled approximately $30 million, of which approximately $5.3 million was classified as maintenance CapEx.

The partnership did not make any capital contributions related to it's Ohio gathering JV in the second quarter of 2016. We had $720 million of debt outstanding under our $1.2 billion revolving credit facility at June 30, 2016, which implies $529 million of available borrowing capacity. There was zero net borrowings under our revolving credit facility in the second quarter.

Total leverage as of June 30, 2016 was 4.50 times. SMLP updated its 2016 adjusted EBITDA guidance from a previous range of $260 million to $290 million, to a new range of $270 million to $290 million.

We expect SMLP's average full-year 2016 distribution coverage ratio to range from 1.15 times to 1.25 times. With that I will turn the call back over to Steve.

Thanks, Matt. I think our financial results this quarter display the diversity and resiliency of our business model and the positive impact of the 2016 drop-down transaction that was completed in the first quarter. The drop-down assets are performing as expected, and we continue to believe they will drive future growth at SMLP.

In addition through the first six months of the year our base business has exceeded our expectations highlighting the impact of our highly contracted fee-based business model and the diversity our customer mix, ultimately leading to an increase in the midpoint of our adjusted EBITDA guidance. Through the second quarter we have trended toward the higher end of our financial guidance above our quarterly distribution coverage estimates and below our expected leverage levels, all three positive data points.

Looking forward across the balance of 2016, our outlook is firming, but we continue to remain cautious. In the crude markets we're encouraged with the long-term fundamentals, but remain cautious in the near term. Inventories are near record levels, and producers continue to maintain a robust inventory of drilled but uncompleted wells, not only upstream of our system, but throughout the lower 48. Both of which we think will limit price upside in the short-term, as the market works to rebalance itself over the next 6 to 12 months.

We've had a very constructive spring and summer in the natural gas markets with power burn and production declines from legacy gas basins. However, we continue to think that storage levels are weighing on prices, with the primary risk that another warm winter gets us back to a similar position as where we were earlier this year.

We are encouraged by the number of projects slated to come on line in the near term, which should serve to dilute the impact that weather has on gas prices and our bias to the upside, as a normal winter this year has on the potential to provide a boost to prices relative to the current strip. Although we continue to believe the volume outlook for the entire midstream industry will be more challenging the second half of 2016 versus the first half of 2016, we believe our diversified operations and customer base along with our strong portfolio fee-based gathering agreements and MVCs will provide stability and growth in our business during the continued depressed commodity cycle.

On DBU growth we will continue to take a measured approach and as I said the past a quarter-by-quarter approach regarding the pace of distribution growth per unit in 2016. DBU growth will be dependant on not all current financial results but also the outlook for commodity prices and the impact that they will have on our customers' drilling and completion activities. Our focus continues to be on building distribution coverage and strengthening our balance sheet.

So with that I will turn it over to the operator to open it up for questions.

(Operator Instructions)

Kristina Kazarian, Deutsche Bank.

We've seen some of the Utica guys like Gulfport boosting producing or at least talking about higher 2017 production. Can you guys give some color on how much if we looking out into 2017 you think of this you might see on your system or general color on what you're thinking?

Kristina, it's Steve. I think it's a positive. I don't think we were surprised by their -- some of their comments on forward outlook and growth.

Is probably a little early to know exactly where they plan on boosting. I think we'll get some of it. I think Ohio Gathering will get some of it, given it's very large position versus others.

It's hard to know exactly where, but I think given their increase I think it's pretty safe to assume they're going to be running some having some activity on our system into 2017. I think it's positive. I would also I think the increase in NGL prices and the expected outlook by most into 2017, I think you'll see activity in the wet gas window as well, too.

Liquid volumes in the Bakken were challenged this quarter. It looks a little worse I think since those pads were brought off line for further completion. Can you talk about if this down time was expected and how we should think about wells come online in terms of second half of 2016 volumes.

Yes, I will give you a little bit of sense. It's two things. One I don't want to minimize that lower activity also is going to -- is not great for volumes either so it's not come completely related to completions.

But the other phenomena that you mentioned is we do -- what we see there is as producers complete pads due to pressure issues they will tend to bring down pads in and around the area where they're completing. So we saw that affect us mainly toward the back half of the quarter as completions picked up, and I think we're seeing the impact of some of those completions I would say as we're a month, month and half in to the third quarter. So we do expect to see some positive impact from DUC completions there.

Last one I don't want to frighten you guys for next week but just general guide on how we should maybe be thinking about the Analyst Day.

I think we're going to go through a lot of good information. (laughter) We're going to take it through our outlook by area, how we're positioned by area. Then I think as you probably would expect, were going to talk a lot about our views on the deferred payment and the benefits of that and how we plan on addressing it over the next couple of years.

Perfect. Thank you.

Tristan Richardson, SunTrust.

Could you talk a little bit about Summit Utica in the investment you talked about in the second half getting to the 450 million cubic feet a day capacity. Is that of the bulk of the planned spend on the system for the remainder of the year? And then when you look forward in terms of additional spend to build that out will that sort of just be concurrent with your customers' plans and sort of yet to be determined?

Yes, I will try to give you some color a little bit of color. I will tell you we definitely spent the bulk -- call it two-thirds or so of Summit Utica 2016 CapEx the first half of the year. So it will come down in the back half of the year.

And our dehy station is literally in the middle of being commissioned now so the CapEx for that has virtually been spent. I would think about remaining CapEx for 2016 as more well-connect CapEx for us for the most part, so it will be connecting additional production. And we're pretty in sync with our customers there and mainly our anchor customer on connecting a pad and that pad flowing pretty soon thereafter so we don't have a but of lead lag time between our CapEx spend and getting additional revenue.

I would say I've made this comment before. We do get paid to dehy gas in addition to gather it. So there is additional incremental revenue for when we bring on a station and start using it.

Tristan, the next real big spend in the Summit Utica system with the when we bring on the compressions we have three dehy stations right now that have room for compression and then so what we set -- when the volumes of the high-pressure gas start to require compression than will bring that on. And then also charge another fee for that as well.

Matt, is that sort of and out year type A spend, and B would you expect all the volumes coming from your customers on the system to be compressed, or will not quite track 1-to-1?

I'm not Matt, I'm Steve but I will comment. (laughter) The way it works is our customers would have to request compression. We have a fairly as you would imagine a fairly long lead time to put the compression in.

And on Summit Utica they have not requested us to do that yet, and it's a 18 month type timeline for us to put it in once they request it. I would expect depending -- and then your second question is a little harder to answer. We could segregate some of the system, have some of the areas on compression some areas not necessarily on compression, so it just depends on where we set compression first what volumes we have, so it's not necessarily everything goes on compression at once.

Great. Steve, you talked a little bit about just seeing some interesting dynamics in the Piceance and DJ. I'm curious is that primarily based on the fact that some of that acreage has changed hands and so economics are reset, or is there some other macro aspect going on there that we should be thinking about?

And then also was that impact on the quarter? Because I think numbers were little better that than I think some expected.

I will take them in pieces. First, we've had actually a -- most of our acreage trade hands absent Encana's, frankly. So most of the other areas large areas for us have. So three of our top customers now in that area are owned, and this has happened in the past two years, two and half years -- are now private companies private equity backed companies that really this is the only area of significance that they're -- acres they have.

And so we've seen in the last several months in particular seen a pretty aggressive uptick in those customers activity in the area. That could be gas price related. I don't know necessarily think it's the basin reservoir related.

We are seeing some data points on better completion that's just completion technology though taking effect and taking hold versus what it was three, four, five years ago. So we are seeing some positives from that, but I think it's mainly due to new guys coming in repricing the acreage. Usually when private equity comes in and buys acres they don't buy to sit on it.

So we are seeing them develop it. Second part of your question on impact, frankly, there wasn't much of an impact at all in the second quarter related to that activity. A lot of completion activity happened late in the quarter and is happening now as well, too, so I expect we'll see more impact through the second half of the year than we did in the first half of the year with that increased activity.

Steve, that's great. Thank you guys very much.

Lane France, Robert W. Baird.

Can you guys provide us with an update on Ursa in your Piceance and DJ segment with their plan to drill 70 wells by the end of 2017? Any update on the [sense of timing] of volumes with the of number wells brought online out of that agreement so far would be appreciated.

They are in the process of completing I think 16 of those 70 right now. There's a few on, and they are completing a big pad site, so they are in process of that. I think we'll see more benefits of that also as they finish those out in the second half of this year.

Your operating and maintenance expense fell 9% from first quarter to second quarter while your top line revenue and your total throughput was basically flat. Can you help us understand what drove those cost lower and if those inefficiencies are sustainable to the back half of the year?

Part of what skews that a little bit is in the first quarter we had some slip expense in Marcellus segment pipeline slip expense in our Marcellus segment. Those tend to be I don't want to call them one timers because they happen, but it was a big one, big cost I think it was $1 million, $1.2 million something like that in the first quarter.

So, that's a little bit of the sequential quarter comparison, and then we're, candidly we're focused on costs. I think I would tell you we think it's sustainable our levels absent some one timers things like slips, but we do think ongoing it is fairly sustainable. So we're very focused on cost controls and I would say optimization of our system.

Great.

John Edwards, Credit Suisse.

Steve, could you -- you guys raised your guidance, and it sounds like taking into account you had a write down in your Utica Shale segment I guess from that joint venture. Nonetheless, you were able to raise your guidance.

Just talk little bit about how you took that into account and what if you didn't have to write off that asset what was the impact of that? Where could you have gone, perhaps? I'm just trying to get a sense for kind of what the real sort of true increase in expectations is here.

John, the write-down was specific to the condensate stabilizer at our JV. We obviously follow -- MarkWest is the operator, so we follow their lead. They wrote it down, too. We got our proportionate share of that.

So it is a I would say a pretty small piece of the JV from a cash flow perspective. It's probably doesn't take a lot for you to connect the dots on the write-down. There's just not a lot of condensate drilling going on, and that's the biggest piece.

And I think also operators in the area are also just getting better on doing some field stabilization as well, too. So that's occurred. But I would say the impact to us on that both historically and going forward is just a small piece of the business.

You were expecting this -- really not a big deal. And you're still expecting a pretty sharp ramp up in your Utica segment going forward. Is that fair?

That is fair. The biggest driver of our Utica segment is gas, right? So be it from the wet gas area or the dry gas area.

So that's fair. I think to put it into perspective Matt was telling me that the condensate area for us is I think less than 1% of our Company.

The impact is very de minimis, John.

So really this is more of a kind of a housekeeping item. This was expected that kind of thing.

I would agree.

So as far as your longer term outlook then you raised guidance this year. Any change to the longer term trajectory? You may have commented, and I may have just missed it.

No. We've been one to shy away from longer than 12 months guidance. In this market I think it's hard enough to give that. I think we're probably on balance a little more cautious than maybe some others on just the commodity outlook for the balance of the year and then going into 2017.

And I think we want to get a little more clarity as we all go through our budgeting season over the next three or four months, a little more clarity from our customers on their plans for 2017 before we start talking about longer term. But for 2016, as we said in our comments, our prepared comments, I think the back half of the year is firming up very nicely for us.

Mirek Zak, Citigroup.

I was wondering if you could give us a better idea of the relative drilling activity that you're expecting on your Ohio Gathering and Summit Utica systems near the end of year versus what you saw in Q1 sort of irrespective for when the value -- volumes are actually coming online in the system.

Just Ohio Gathering. I think we tried to give you a little bit of color in our comments. But -- so we saw heavy activity at the end of 2015 in the first quarter.

Then we saw that completion activity occur. That's primarily in the dry gas area of Ohio Gathering. That sort of drove volumes in the first quarter I would say into the first part of the second quarter.

Not much activity in the second quarter drilling or completion activity. And then we expect both to occur, drilling and completion activity, to occur in the area in more of an impact later third and into fourth. That gives you -- and more so in the wet gas window from our customers.

And that's important just because the magnitude of volumes of molecules we move between wet and dry are just different. Little lower in the wet gas area versus the dry gas wells tend to be higher IPs. Does that help you?

Yes. How do see the cash flows net to Summit from those systems the Ohio versus Summit sort of growing relative to each other over the next couple of years?

We own 100% of Summit Utica so that helps -- only 40% of Ohio Gathering. So I think -- Ohio Gathering is a more mature system than Summit Utica. Summit Utica we're still building out quite significantly, connecting pads and pretty active on the front end of that.

So the magnitude of growth and volumes from Summit Utica will be greater because of those two factors. One we own 100%, two we're still building it out and connecting it. We do still expect obviously OGC to grow and still have very nice growth, but Summit Utica will be the bigger driver.

Lastly I think you touched upon it earlier, but can you give us an idea of the split between dry versus wet gas volumes that you are currently gathering on Ohio Gathering system. Is that mostly dry right now?

On OGC, it's probably 50/50 is what the guys are telling me.

Summit Utica obviously is 100% dry.

Jeff Birnbaum, Wunderlich.

Most of my questions have already actually been asked and answered, so maybe a few just sort of smaller housekeeping ones. The connectivity on Polar and Divide and the new take way you referenced in the release and [now] thinking you prepared remarks Steve can you give a little bit more color on the potential CapEx involved there. Is that included in guidance or if that would be incremental to that and sort of what visibility you have into maybe the impact that could generate of volumes.

Yes, first, it's included in our guidance. It's not a major project. It's an interconnect, so less than $10 million project for us.

It's not really a volume impact, Jeff, because it's more of us making incremental margin on our already gathered barrel. So we have an additional interconnect potentially can charge for that additional interconnect for our customers to access it. So we're gathering that barrel so it's a matter do we take it to X location or Y location, and we just make a little additional if we take it to a different location.

So that's how I would think about it. That's very positive for us right because you are making more margin on the same barrel. But it's not -- it's a great little project, but it's a little project. It's not a huge mover.

To be clear it helps our customers net back in the areas willing to provide access.

We think it's very strategic to be up able to connect to DAPL obviously.

That was kind of where is getting at whether you sort of had an indication from your customers that, that basically the net back -- that improvement in net back would be an incremental difference maker.

I will put it this way. I think there's a lot of discussion on DAPL because it's so big its impact to the basin and how customers feel about it given a $40 crude oil environment.

My discussion with them and I've had discussions with them some large shippers on them. I would say and maybe [transfer] will pay us for some of IR here, I would say the folks are very positive and looking forward to DAPL coming online.

Fair enough. I guess something of I guess of a related question, you also mention that you're already seeing some impact from those DUCs turning into sales that were sort of shut-in in the second quarter. Is that pretty locked in as far as you know from your customers' plans or I guess kind of how much depended is that turn to sales in the back half on pricing?

I would say for us what we're seeing the completions are going on now. So pre locked in. Those decisions were made a couple of months ago most likely, and so we have always -- you've heard us say the cycle time from spud to volume for us is I would call it nine to 12 month.

But the cycle time from completion to volume to us is probably somewhere in the three, four months timeframe. So it's pretty -- if that makes sense it's pretty -- those are pretty well locked in I would say additional activity obviously going to be price dependent.

What we saw, or what we've seen is as prices trend and this is what we thought would occur in the sequence it has as prices trended towards $50 a barrel we saw DUC completions happen first and then rigs come in second and I think that's what will see. I think will continue to see DUC completions as prices bounce between $40 and $50 and then think it's going to take north of the $50 before you see rigs being added.

Perfect. CapEx looks to be more than half -- for the year looks to be more than halfway done as we get past the halfway point of the year. It sounds like the second-half budget other than maybe that one project is mainly well connects.

So sorry if I missed it, but you haven't updated expectation for leverage at year end? This is probably going to be covered next week too.

Absolutely, Jeff, this is Matt. Just from a CapEx stand point we already spent about $100 million in the first two quarters and I think our guidance was $150 million to $200 million. Our expectations right now are to be on the low end of tate guidance from a CapEx standpoint, and most of the activity as you can imagine would be kind of Utica related getting the dehys done as well as Bakken related as well is most of the CapEx.

From a leverage standpoint as we mentioned before where about 4.5 times here at June 30. As the year progresses we expect to probably get a little closer to 4.75 times without any other activity and changes relative to our guidance and then as we mentioned we expect that to delever in 2017.

Charles Marshall, Capital One.

Most of my questions have been asked and answered, but just a quick couple of ones here. With regard to Encana and the Piceance, do you have any updates with -- thoughts with them or any negotiations right now to try to entice activity there? Or any update with that customer would be helpful.

I would say not a great one other than they I think have made it pretty clear publicly in some of what they're doing is I think they are probably studying the area what their plans are going to be. We have a very good relationship with them. We stay in contact with them and would love for either them or someone else to be more active for sure.

But we're not privy to their strategic discussions around it other than what we see publicly going on with [reqs] capacity, redetermination things like that. We are levered to that if anything does trade their I would say it's probably a positive for us. General acreage trades have been very positive for us.

That make sense. Extrapolating that forward to the Barnett, do have that same feeling with Chesapeake and that acreage there? Obviously is to have a lot of talks about them looking at the Barnett and maybe selling that acreage. Would you see that as a net positive relative to where things are happening today?

Yes. Chesapeake and Encana haven't really drilled a well in the last three years on our systems. They are a large acreage, the largest acreage holder Chesapeake is in the Barnett on our system. Again, that acreage trading usually foreshadows increased activity for us.

So to the extent that occurs, and we've been watching it probably just like you guys have pretty closely and are pretty in tune with it. I think that would be a net positive to Summit. I will say we also probably have Chesapeake -- we venture to say we have their best acreage in the Barnett it is around our system.

I know you guys in some of the outer years have a lot of CapEx allocated to compression. Is there any thought of any change in that cadence of spinning those dollars for compression? Do you see that having to come on, sooner rather than later any color around that would be helpful.

I think you mean the Utica specifically. It's a little tough to tell.

It's largely customer driven on how they want to manage the field. That optionality lies with them on when they want us to put compression in typically. We're doing that at OGC in the dry gas area.

I think that was mentioned yesterday by Gulfport on the call, so we are adding compression there. We don't see us in a compression at Summit Utica as I mentioned earlier in the call for a while.

Yet it's obviously a newer development so that would make sense. It's the out years. We definitely projected and planned for it the exact timing, exact quarter gets a little cloudy right now because it's customer driven.

See you next week.

Thank you.

We have no additional questions at this time. I would like to turn the call over back to Mr. Steve Newby.

Thanks, everybody, for joining us and hope everybody has a good weekend and we look forward to seeing you next week, next Wednesday in Pittsburgh for analyst day. Thank you.

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