Summit Midstream Partners LP (SMLP) 2018 Q1 法說會逐字稿

Welcome to the Q1 2018 Summit Midstream Partners, LP Earnings Conference Call. My name is John, and I'll be your operator for today's call. (Operator Instructions)

Please note the conference is being recorded. And I will now turn the call over to 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 2018.

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 our homepage or in the News section.

With me today to discuss our quarterly earnings is Steve Newby, our President and Chief Executive Officer; Matt Harrison, our Chief Financial Officer; Leonard Mallet, our Chief Operations Officer; and Brad Graves, our Chief Commercial 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 2017 annual report on Form 10-K, which was filed with the SEC on February 26, 2018, as well as our other SEC filings for a listing of factors that could cause actual results to differ materially from expected results. Please also note that on this call, we will 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.

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

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 details on our quarterly financial results.

Yesterday, we announced our first quarter 2018 operational and financial results, which were in line with expectations and included $70.3 million of adjusted EBITDA and $44.2 million of distributable cash flow. These results keep us on track to achieve our 2018 financial guidance targets. On April 26, we announced our first quarter distribution of $0.575 per unit, which implies a first quarter distribution coverage ratio of 0.98x. As expected, the $300 million preferred equity offering issued in the fourth quarter of '17 weighed on distributable cash flow. While our first quarter distribution coverage is below our long-term target range, it is in line with expectations, and we think that the short-term trade-off was appropriate given that we satisfied our near-term and medium-term equity needs and strengthened our balance sheet.

This capital raise enabled us to post a 3.6x leverage ratio at March 31. We have ample leverage capacity and fully funded 2018 capital plan and visibility to adjusted EBITDA growth and strengthened distribution coverage towards the end of this year and into '19.

As a result of a number of recent conversations with investors and sell-side analysts, I'd like to make one thing clear, our distribution is secure and sustainable and at this time there is no need for us to reconsider our current distribution payout. Our leverage is moderate, our Capex is fully funded and we have visible and accretive EBITDA growth. We made a deliberate decision over the last several years to focus on accretive organic growth versus large dilutive M&A transactions. We understood the ramifications of this would be a slower growth profile coming out of the commodity cycle until these projects ramp-up. However, we now feel stronger than ever that this approach will be beneficial to our unitholders over the next 12 to 18 months as organic growth kicks in, our coverage expands and our balance sheet remains strong.

Our optimistic expectations for near-term growth are primarily related to Summit's northern Delaware, DJ, Bakken and Utica assets, all of which we expect to be generating higher EBITDA, or in the case of the Delaware, begin contributing positive EBITDA in the fourth quarter of '18.

As for '19, we expect the DJ, the Utica and the Delaware to be significant growth catalyst for us as those areas ramp in volumes. In the northern Delaware, we continue to dedicate a tremendous amount of focus on expanding our footprint, which today consists of a natural gas gathering and processing system that is under construction and underpinned by XTO Energy. Since our project announcement in third quarter of '17, we have added 3 new customers in additional acreage dedication. We're also excited to announce that we have recently reached an agreement to expand our service offering, and we will begin providing crude oil gathering for existing customers in our catchment area in early 2019. We expect this entry into liquids gathering in the Delaware will allow for additional expansion opportunities for Summit in the future.

With respect to our proposed Double E Pipeline project, in January, Summit announced a nonbinding open season. As many of you know, crude oil and associated natural gas production in the northern Delaware is growing at a rapid pace, and we believe that incremental residue gas takeaway capacity was needed and producers are going to achieve their long-term production target.

We have received significant interest in Double E, which will provide much-needed takeaway solution by aggregating natural gas from multiple receipt points in the area, including our own processing plant and providing transportation to the Waha Hub. In last night's earnings release, we announced we are looking at expanding the project in excess of the 1 billion Bcf a day of initial capacity originally contemplated. This is a marquee project for Summit as it diversifies our service offering, allows us to offer an integrated solution to our customers and will provide a base of highly-contracted cash flows, post completion.

I'm going to discuss Double E further a little later in the call. We are close to finishing construction on our 60 million a day associated natural gas gathering and processing project in northern Delaware and the project is on time and on budget. We expect mechanical completion in June, with first gas flows beginning in the third quarter of '18. As I've previously mentioned, we expect to see the financial benefit from this asset beginning in the fourth quarter of '18 as volumes ramp up. Based on our customer's drilling plans, our current expectations are for a steady ramp from the fourth quarter well into 2019 and beyond. This facility is readily expandable, and we're actively working with existing and nearby producers to optimize the asset. I'll also note that the Double E Pipeline will originate at the lane plant, so stay tuned for further development here.

Our outlook for our Bakken assets have improved significantly in the last few months due to efficiency gains and higher crude oil prices, which has led to sustained drilling and completion activity in our service areas. Increased takeaway capacity, most notably DAPL, has enabled our customers to improve their netbacks and allocate additional capital to the area. We've also had a couple of recent commercial wins that have brought new 2 customers on to our Polar & Divide system. These accretive projects will help solidify what we expect to be double-digit liquids volume growth behind our Williston system in 2018. Additionally, existing customers in our Williston assets have recorded attractive results from their recent wells. We are particularly encouraged by strong recent well results in northern Williams County, an area that has been less active during the downturn but has seen an increased level of activity over the past 6 months.

We believe that the result of these recent wells may be an additional catalyst for incremental drilling in this area.

In the Utica, we are seeing basis differentials narrow due to increased takeaway, specifically the nearly completed Rover Pipeline. Higher producer netbacks and improving liquids prices are spurring producer activity across Summit's dry gas, wet gas, and condensate service areas. Increased activity in these areas will provide a significant benefit to SMLP in the near term and in the long term. On SMU's -- on Summit's SMU system, we recently received notification of increased drilling and completion activity for the balance of 2018 and into 2019. The increased activity from our customers will begin in the second quarter of this year and continue into 2019, with the majority of volume growth coming in the second half of 2018 and into 2019. SMU volumes averaged approximately 350 million cubic feet a day in the first quarter. We're now moving 450 million cubic feet, and we'll complete a small debottlenecking project this summer to increase capacity to 600 million cubic feet a day.

Now, I'll turn it over to Matt to review our financial results in more detail.

Great. Thanks, Steve. SMLP reported a net loss of $3.8 million for the first quarter of 2018 compared to a net loss of $600,000 in the first quarter of '17. The first quarter of '18 included $21.7 million of noncash deferred purchase price obligation expense or DPPO expense. In conjunction with the 26 (sic) [2016] Drop Down transaction, we recognized a liability on our balance sheet for the DPPO to reflect an estimate of the remaining consideration to be paid in 2020 for our acquisition of the 2016 Drop Down assets. We just count 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 adjustment to the expected value of the DPPO.

Adjusted EBITDA for the first quarter of 2018 totaled $70.3 million compared to $71.4 million for the first quarter of '17. The $1.1 million decrease in adjusted EBITDA was primarily due to the recognition of a $2.6 million business interruption insurance recovery at our Williston Basin segment in the first quarter of '17, offset by a $1.4 million of increase in adjusted EBITDA in our Ohio Gathering segment in the first quarter of '18 compared to first quarter of '17. Adjusted EBITDA in the first quarter of '18 included approximately $14.3 million related to MVC mechanisms from our natural gas gathering and crude oil transportation agreements. Additional tabular detail regarding MVCs is included in the first quarter earnings release.

Total operating natural gas volumes increased -- averaged 1.7 billion cubic feet per day in the first quarter, a 6.8% increase over the prior year, led by higher volume throughput in the Utica and in the Marcellus. In the Utica, our wholly owned and operated Summit Midstream Utica system gathered 356 million cubic feet per day in the first quarter, up over 29% from the prior year period, due to 15 new wells in 2017, including 2 new wells in December of 2017. The first quarter of 2018 also included 40 million cubic feet per day of additional volume from the TPL-7 connector project, which was started in the second quarter of 2017. SMU volumes were down 4% relative to the fourth quarter of 2017. The quarter-over-quarter decline was primarily a result of 15 million cubic feet per day of production being temporarily curtailed upstream of the SMU system. These volumes were brought back online by the end of the quarter. We're in the process of connecting multiple pads and expect significant volume growth resuming behind the SMU system beginning in the second half of 2018.

For Ohio Gathering, volume throughput in the first quarter of '18 was 771 million cubic feet per day, relatively flat with the first quarter of '17 and down 7% from the fourth quarter of '17. Volumes decreased relative to the prior quarter due to natural declines from wells brought online in the second half of 2017. Although no new wells were connected in the first quarter of '18, we expect over 40 new wells being brought online throughout 2018.

Our liquids gathering business in the Williston Basin averaged 85,000 barrels per day in the first quarter, up 15% from the fourth quarter of '17, and up 11% from the prior year period. 46 wells were brought online in '17, including 20 new wells late in the fourth quarter of '17. 10 new wells were brought online in the first quarter of 2018. Liquids volumes also benefited from the addition of a new customer that accounted for approximately 20% of the quarterly volume growth. Liquids volumes in the first quarter of '18 were negatively impacted by an estimated 13,000 barrels per day related to trucked volumes from certain pad sites due to capacity issues at third-party produced water disposal sites and temporary crude oil production curtailments from certain customers completing wells on existing pad sites. We've forecast volume growth to continue throughout 2018 supported by an existing backlog of over 35 DUCs. Also, we currently have 4 rigs working in our Williston Basin service areas.

Our Piceance/DJ Basin segment averaged 578 million cubic feet per day in the first quarter of 2018, down approximately 6% compared to the first quarter of '17 and relatively flat to the previous quarter. New well connections were more than offset by natural production declines on the Piceance/DJ Basin systems. In November, we announced the 60 million cubic feet per day processing plant expansion in the DJ Basin. This expansion remains on budget and on schedule and is expected to start in the fourth quarter of 2018.

In the Barnett, volume throughput averaged 263 million cubic feet per day in the first quarter of 2018, down approximately 8% compared to the first quarter of '17, and increased slightly from the fourth quarter of '17. 6 new wells were brought online in the fourth quarter. We have 1 drilling rig working on our system currently and expect additional wells in the fourth quarter of 2018. This drilling activity will offset some of the natural production declines.

Volume throughput in our Marcellus segment averaged 522 million cubic feet per day in the first quarter, a slight decline from the previous quarter, but approximately 20% higher than volumes in the first quarter of '17. Volumes compared to the prior periods were positively impacted by 27 new wells in 2017. Also, we had 9 wells come on late in the first quarter of 2018.

Turning back to the partnership. Distributable cash flow totaled $44.2 million in the first quarter, which implied a distribution coverage ratio of 0.98x relative to the first quarter distribution of $0.575 per common unit to be paid on May 15. CapEx for the first quarter totaled $40.8 million, of which $3.8 million was classified as maintenance CapEx. We have $301 million outstanding on our $1.25 billion revolving credit facility at March 31 and $949 million of available borrowing capacity. Total leverage as of March 31, 2018, was 3.63x. SMLP also reaffirmed its 2018 financial guidance. We expect 2018 adjusted EBITDA to range from $285 million to $300 million. Total CapEx is expected to range between $175 million and $225 million, including $15 million to $20 million of maintenance Capex. We expect distribution coverage for the full year to range between 0.95x to 1.05x.

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

Thanks, Matt. I'm proud of the momentum of Summit's organic growth catalysts which we have developed over the past several years. Our 2018 capital program is financed and our balance sheet is strong. We're forecasting significant EBITDA growth beginning in the fourth quarter of this year and into '19, and we expect distribution coverage to improve in parallel.

I'll reiterate, with our low leverage and near-term capital needs met, we have no need to reconsider our current distribution level given our outlook today. It is sustainable and supported by our leverage and liquidity metrics and will be further supported by the anticipated growth of development projects underway, which we have already funded. As I mentioned earlier, we have received significant interest on the Double E project, and we are moving forward with the next steps on solidifying our final investment decision. We expect this decision to be made in the third quarter.

The capital estimate for the initial development is $400 million to $450 million, pending a final decision on route and pipeline size. Project-related capital expenditures are expected to be modest in 2018 and 2019, with more meaningful expenditures occurring in 2020. We expect less than 15% of the total capital to be spent in '18 and '19 combined as we work to obtain the FERC permit. The balance of the capital spend will fit nicely in our medium-term capital plans and will occur at a time when CapEx on other systems is moderating and at a time when we are expecting to generate much higher EBITDA. The target end service date for the project is the second half of 2021. Given the attractiveness of the project, Summit has received interest from potential shippers and other parties concerning equity participation in the project. Our team is evaluating those alternatives and we expect to make a decision in conjunction with the final investment decision on the project. Given the length and the timing of the spend and the potential for partners, we did not expect any issues financing Double E.

In the DJ, we continue to execute our gathering and plant expansion, which remains on budget and on schedule for the fourth quarter '18 in-service date. We have an expansive footprint with over 180,000 dedicated acres, and we're encouraged by activity levels from our 2 anchor customers, along with potential third-party opportunities in and around our footprint. In fact, during the quarter, one of our anchor customers closed on a major acreage acquisition in the area and announced their drilling plans over the balance of '18 and '19. These plans exceeded our expectations, so we anticipate a very healthy level of utilization in our DJ plant for 2019.

Driven by these Delaware and DJ expansion projects, together with growth behind our Bakken and Utica assets, we continue to forecast significant volume and adjusted EBITDA growth resuming in the fourth quarter and into '19. One indication of our increasing confidence is the increase in the deferred payment obligation to $517.1 million, as subsequently reported. This increase is related to the higher EBITDA contribution and lower associated CapEx from the drop down assets. We have prefunded a significant portion of our equity needs related to deferred payment obligation and as EBITDA ramps over the next 18 months, our leverage capacity will simultaneously expand, allowing us to address the payment. As you all know by now, if that EBITDA does not increase or ramp as expected, then the deferred purchase price obligation will come down.

Looking beyond 2018, I'm excited by our backlog of project opportunities. Our commercial team is working diligently. And while we won't win them all, we are optimistic about our ability to prosecute accretive opportunities in and around our existing service areas. We fully appreciate the challenges we currently have with our cost of capital or even access to public equity capital. However, we remain very confident in our ability to access private capital and other alternative sources to fund good, accretive growth projects. Our primary focus here is driving long-term value for our unitholders.

So with that, I'll open it up to the operator for questions.

(Operator Instructions) And our first question is from Chris Tillett from Barclays.

Just wanted to first touch base back on your Utica segment. So you mentioned there that volumes were impacted by curtailments during the quarter. Just curious were those curtailments more price related or operational?

Chris, it's Steve. No, we had -- one of our major customers had an operational issue that actually bled over to us. We had to shut down part of our system for most of February, actually -- or about 1/3 of our system I should say, for most of February. So they had an issue on a pad, on a well there, that caused that. So that's now been cleared up and things are more than back to normal as I mentioned in my commentary that sort of where we are on volumes.

Okay. Is that at all related to kind of the improving outlook behind those assets that you guys had talked about or, I mean, is that a separate customer?

I wouldn't tie the two together. I think the improving outlook's more related to, obviously, basis improving with Rover, liquids price is improving as well. We're actually having a fair amount of pretty high level of activity in the (inaudible) segment right now on OGC. So I would attribute it more to that than the operational issue. That was a little bit of a onetime event, that's how I would put it. It did cost us about, I think, 20 days or so of volume on about 1/3 of our SMU system.

Okay. Makes sense there. And then moving to the Piceance. Is there any update that you guys can provide on the suspension of activity from one of the anchor customers there that you guys have talked about previously?

I don't think it's -- you're talking about the Caerus guys and their purchase Encana. I think their focus right now on the northern part of the acreage that they acquired with that purchase. But I would say, and Brad Graves, Brad you can comment on this too, but I would say discussions are actively going on with them about things in our area as well too. So Brad, I don't if you have anything to add...

No, no, that's right. I mean, I think Caerus continues to get their arms around what they purchased from Encana. But we are talking to them on a number of fronts.

Our next question is from Praneeth Satish from Wells Fargo.

I think I've heard you mention that Summit Utica is running at 435 million cubic feet per day. It's a big increase over the Q1 level. Do you think that can be maintained into Q2 or how should we -- or should it come down a bit? How should we model that?

Yes, Praneeth, that's actually running at about 450 million right now. And a good portion of the increase so far has been our high-pressure service, if you probably remember, as us refer to it as our TPL-7 service. So little bit less of a fee than our wellhead gathering. But still, volumes have ramped up nicely there. I would tell you, no, our outlook for SMU is actually increasing volumes throughout '18, more the back half of '18 and then a pretty strong outlook into '19 as well too. I'll mention, we are doing a debottlenecking, small debottlenecking project there. It's actually increased our capacity to 600 million a day. That system was built, you may recall, as a 0.5 Bcf system initially, but we're debottlenecking it for, sort of, close to nothing and getting about 100 million a day more capacity, so we're pretty bullish on the outlook of SMU, particularly as we get to the end of this year and into '19.

Got it. And then just, I guess, maybe without any specifics but can you just talk about the shape of your CapEx spending over the next few years. If you proceed with Double E, should we assume that the current run rate of around $200 million per year, it will stay on that level until the buildout's complete?

Yes, I'll take a shot, Matt, you can add in. But I'll go first. I would say that, as it stands right now, and our outlook would be actually CapEx being lower next year than $200 million. Again, Double E's spend between the rest of '18, assuming we FID it here in the third quarter, and into '19 is pretty de minimis. And the reason is, we're doing the FERC -- we're basically in the middle of the FERC filing. We may choose to buy, we may choose to make steel purchases earlier. That would be a choice we make depending on the market and what we want to do there and I think everybody knows probably what's going on with steel. So -- but I would tell you right now, Praneeth, that if -- where we sit today is actually we'd be looking at CapEx a fair amount lower, actually in '19. Now that being said, we're actively working on growth projects, we're actively looking at things, and so I expect that to change. But if you ask me where we're sitting today, that's where I'd tell you. The other thing I'd tell you, I think, is we're pretty confident in how -- it's not just CapEx, it's obviously how we view the business ramping up from a cash flow perspective and our leverage capacity and also I want to make the point, we pretty effectively funded our deferred purchase price at this point. It's pretty close to being done we've issued $400-plus million of equity so far over the last 18 months related to it. So we feel good about how all of this lays out over the next 2 years. You have any -- Matt, you have anything...

No, I would agree. So we'll be down on a CapEx standpoint in '19 but obviously up relative to cash flow in '19 compared to '18. And then as -- again, assuming Double E, you should expect 2020 CapEx to increase back up, maybe to '18 levels. But we certainly will be down in '19 and up in cash flow.

As it sits today.

As it sits today.

Our next question is from Tristan Richardson from SunTrust Robinson.

Just a quick one on the Utica. In the past you guys had targeted about 50 completions in 2018, but now that we have sort of a subsequent news on higher expected D&C activity and us driving the deferred purchase. Can you update your thoughts just, sort of, with those new details around completions you expect this year, especially with where volumes are running today?

Yes, go ahead Matt.

Yes, I mean, I think, when you say Utica, you're assuming both SMU and OGC. And we can get specific -- we're probably close to 8 completions at SMU in '18. We're expecting to double that in '19. And then as it relates to OGC, what are our expectations for OGC?

30 to 40.

30 to 40 in OGC in '18. So that's still relatively consistent from that standpoint.

Let me footnote something there too, Tristan, just to try to right set you a little because I think we talked about in the past and we need to reiterate, where the completions come is critical, right? We're -- in our dry gas area, let me just give you an example, we brought on 2 wells at the end of -- in the last year, those 2 wells are doing north of 30 million each on 1 pad.

After 6 months.

After 6 months without compression. So when we say 8 wells or 7 wells dry gas area, you can probably do the math. I don't think all of them are going to be that big but these are big, big wells in the dry gas area. Conversely, on OGC, of the 30 to 40 completions there, there's going to be some wet gas completions. There's also going to be a fair amount of condensate completions and those are smaller wells, from a gas perspective than what we move. So that -- the composition of those really matters is what I'm trying to get at. I don't want to state the obvious but I want to point that out.

And obviously, we only own 40% of OGC.

Yes.

Makes sense. That's helpful. And just curious, sort of, with where volumes are trending now as you guys have talked about, a lot of that having to do with TPL. But -- and just sort of where you guys are seeing a higher D&C activity, could you sort of reconcile that with the -- a customer's decision to defer compression. Are those 2 kind of unrelated or do you have input there?

Yes, they're actually somewhat related. The reason is, if you're drilling more new wells that don't need compression, you don't want to pay an additional fee on new big, strong wells because it's centralized compression, right? So we can't segregate, obviously, volume at the pad, it's centralized. And so the 2 are somewhat related, a higher level or increased level of drilling over the next 2 years led to decision of, hey, why don't we hold off on centralized compression given we're going to have a fair amount of new volumes come on that don't need it. Makes sense?

That makes sense. Yes, absolutely, Steven. And just last one for me. In terms of the crude gathering initiative in the Delaware, just kind of curious sort of any capacity you're thinking about or also, sort of, downstream connectivity, where gathering would connect to, et cetera?

Yes, let me -- so first, I'm trying to figure out how to answer the downstream because I don't want to -- it will lead into some of our peers and some (inaudible). But I think, I'll just state the obvious. Plains has got a pretty good connectivity in that area and so they'd be a logical choice, there's also some refiners connectivity in that area. Eventually, XTO wants their barrels and has a plan, they've been public about it, about moving their own barrels and getting those to the gulf, so I would say all of the above. We have an advantage in this area. I want to reiterate this point to folks, this area is unique in that it's a lot of BLM land that presents challenges on timing of permits but it's also an area that is -- there is a lot of, what we call, potash mining. And so the -- what that does is the BLM becomes very precise on how you route pipelines and they also aggregate producers into large drilling islands. So you'll have 2 or 3 producers on what we would call a pad, they call it a drilling island, so -- but it's a little bit bigger than a single pad. I bring up that point because once you get that right of way to that pad and in that area, you basically have an advantage, quite frankly, to do multiple service offerings, crude, water and gas. We're utilizing that advantage. This is our first deal. It's not going to be a huge amount of volumes yet. We're picking up a few pads, few producers, but what we anticipate is that service to grow over the next several years as we build out the system over there -- up there overall. So that help a little bit?

Our next question is from Jerren Holder from Goldman Sachs.

So there appears to be a little bit of a disconnect, I think, between the deferred purchase price obligation and maybe what the street is modeling in terms of EBITDA. Is there a way for you guys to give a little bit more clarity around maybe some of the components that goes into that calculation? Maybe some of the CapEx that's been spent to-date, EBITDA generated to-date, G&A? And maybe how you're think about EBITDA into 2019?

You want to get that?

Yes, this is Matt. I'll kind of highlight a few things and it's really kind of consistent to what I mentioned last quarter as well. Some items have moved up, some items have moved down, but it's generally consistent. And if you think about the way the calculation works, it's average of 2018 and 2019 EBITDA, right, times 6.5 and you minus some 13.6% of, kind of, normalized G&A then it times 6.5, I think. But if you think about that calculation, it's -- we did about $100 million from those drop down assets in EBITDA in 2017. We're expecting it relatively flat in '18. And if you kind of back into the implied average EBITDA, it's around $125 million for the average for '18 and '19. So that implies to me some very significant growth relative to those drop down assets in '19. If you're starting at a $100 million, you can average around $120 million, $125 million. So hopefully that helps. And basically, the CapEx generally offsets itself with the amount of EBITDA enjoyed kind of from the initial Drop Down.

And that -- as we think about those EBITDA numbers, those are -- I know there's a net component for the G&A that's in there and so that's already adjusting for that?

Correct.

Yes.

And Jerren, if I could just take a step back to make one point. We did this transaction in '16 in the middle of the -- obviously, of the down cycle. Some of our other peers did other transactions. We did this deal at 6.5x and we did this deal with ultimate amount of flexibility in financing it. So this deal is going to be accretive, there's no doubt about that, to the partnership. And we gave ourselves 4 years to finance the transaction. So I agree with you, the market's not -- they're understanding it, or not giving us any credit for it. And I think that's a mistake.

And then -- maybe moving on to the Bakken. Some of other midstream operators seem to be indicating some pretty strong trends there even just in the second quarter versus the first quarter, as volumes not only recover from the first quarter disruptions but just seems to be trending well. What are you guys seeing on your assets, quarter-to-date, and kind of expectations for the rest of the year?

Yes, I think we came out with guidance and then we'd reiterated here. We expect double-digit volume growth year-over-year on the liquids side in the Bakken. We're seeing the same thing, we got 4 rigs running on our acres now, which sounds great but the other thing we're seeing is just the efficiency gains and some of the completion techniques that have been used in other places. The Bakken is -- probably been slower to develop, really loading up on proppant and lateral length. And now they're -- that's catching up, and you're just seeing some really impressive wells there. And again, this is -- our service offering there when we -- on most of our system when we get crude, we also get water. So we're making revenue twice, typically, on a pad there. But we would say the same thing. We're also encouraged, if you note in our comments, that northern Williams County area, or what we call our Blacktail system, is starting to see some pretty nice results. We've added 2 customers in that area in the past 6 months and I think it's going to spur some other activity, is what we expect here over the next year in that area.

And just a little bit of a footnote, if you think about the 13,000 barrels a day, we talked about being off-line whether it's related to saltwater disposal issues or kind of frac protect. If you run that through, that's about $1.5 million to $2 million of EBITDA impact in the first quarter. So we have a little bit behind us as well.

(Operator Instructions) Our next question is from Kyle May from Capital One Securities.

Just a quick one on the Double E project. You've talked about potentially bringing in equity participants for that. Can you maybe help us understand or get a sense of the magnitude of participation you might be willing to take on? And then a follow up to that would be, how you're thinking about financing your portion of the project?

Yes, I'll take it first. Matt can -- look, I think it's a little early on the magnitude. Those discussions are pretty active and ongoing. I don't think we -- we obviously aren't going to give up control of the project, to probably state the obvious. So I think it's just a little early but we -- it's from multiple parties. I think it's an attractive project and people see that and we'll see where it all lays out. Matt, you want to touch on just, our financing or our outlook on it.

Yes. So I mean, just in general, we've given you guys a lot of, I think, information in Steve's comments and our earnings release as well, right? We expect, one, we're getting a high level of interest, we expect around -- the CapEx to range between $400 million and $450 million. The spend curve is really back-end loaded, right, with 15% to 20% of spend occurring in the first 18 to 24 months. So it's really kind of a back-end loaded expense. And that fits in well with our -- kind of, our CapEx requirements on other projects as well as our EBITDA ramp. So target in-service date of 2021 and all of that, the potential JV opportunities from potential shippers and financial -- and as well as the interest in the line, all that's interrelated. So it's just a little early to talk about what percentage, if any, we would go and then I'll also just finish in saying and reminding everybody that all or part of the consideration for our deferred purchase price obligation can be made in common equity at the MLPs option. So we always have that piece available, whether the public equity markets are available, private capital is available or well, that's something at the control at the MLP all the way through.

And Kyle, I think, when we announced the -- we make our final investment decision and announce that we definitively are going forward with it, we're going to have a financing plan for it. So I don't think we're going to sort of leave it hanging out there, not in this world.

And we have no further questions at this time. I'll turn it back over to Steve Newby for closing remarks.

Well, thanks everybody for joining. And if -- again, if you have further questions, follow-up questions, feel free to give us a call and have a good weekend. We appreciate it. Thank you.

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