歐尼克 (OKE) 2017 Q1 法說會逐字稿

Good day, and welcome to the First Quarter 2017 ONEOK and ONEOK Partners Earnings Call. Today's call is being recorded.

And at this time, I'd like to turn the conference over to Mr. T.D. Eureste. Please go ahead, sir.

Thank you, and welcome to ONEOK and ONEOK Partners First Quarter Earnings Conference Call.

A reminder that statements made during this call that might include ONEOK or ONEOK Partners' expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provisions of the Securities Act of 1933 and 1934. Actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

Our first speaker is Terry Spencer, President and CEO of ONEOK and ONEOK Partners.

Thank you, T.D. Good morning, and many thanks for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners.

On this conference call today is Walt Hulse, Executive Vice President, Strategic Planning and Corporate Affairs; Derek Reiners, Chief Financial Officer; Kevin Burdick, Chief Commercial Officer; and Senior Vice President, Wes Christensen, Operations.

Before I hand the call over to Derek, I have a few brief opening remarks. Our first quarter 2017 financial results have us off to a solid start for the year. As expected, we have seen volume growth across our business segments as we begin the second quarter. I would like to reiterate that ONEOK's 2017 guidance expectations have not changed. We continue to expect volumes to be weighted towards the second half of the year in both the natural gas liquids and natural gas gathering and processing segment.

In the natural gas liquids segment, we expect increases in NGLs gathered and fractionated as a result of anticipated increases in ethane exports and the startup of new world-scale petrochemical facilities, as well as benefits from the ramp-up of recently connected natural gas processing plants and increased drilling activity. The increase in producer rig activity across our natural gas gathering and processing footprint also supports a second half of the year natural gas gathered and processed volume ramp.

We're excited about the pending merger transaction with ONEOK Partners, which better positions us to continue to execute on our long runway of organic growth opportunities. These growth opportunities are driven by our extensive and integrated asset footprint, well positioned in several active shale plays providing our customers with full service capabilities in many areas.

I'll now turn the call over to Derek for a brief discussion of ONEOK and ONEOK Partners' financials. Derek?

Thank you, Terry. ONEOK maintained a healthy, nearly 1.3x dividend coverage in the first quarter 2017 based on cash flow available for dividends and had more than $300 million in cash and an undrawn $300 million credit facility.

In our 2017 financial guidance announcement on February 1, we provided guidance for ONEOK's full year 2017 distributable cash flow on a posttransaction basis. ONEOK's first quarter 2017 distributable cash flow, the metric we planned to use following the transaction, totaled nearly $325 million with a dividend coverage ratio of 1.46x, reflecting our excess coverage on a consolidated basis.

ONEOK's higher dividend coverage over the long term is expected to provide greater flexibility, enabling us to reinvest in the business, reduce the need to access the capital markets posttransaction and sustain a level of dividend growth as market conditions fluctuate.

As Terry mentioned, ONEOK's 2017 guidance has not changed and includes an expected 21% dividend increase to $0.745 or $2.98 per share on an annualized basis for the first quarterly dividend following the completion of the transaction, with subsequent dividend growth of 9% to 11% annually through 2021.

Additionally, we expect to reduce consolidated debt to adjusted EBITDA to around our target of 4x by late 2018 or early 2019, driven by expected growth in adjusted EBITDA and the use of excess cash on hand to repay debt or fund capital growth projects.

The partnership's higher first quarter results reflected increased fee-based services across our footprint, which drove higher first quarter adjusted EBITDA in all 3 business segments compared to the same period last year. ONEOK Partners' distribution coverage ratio was 1.10x for the first quarter 2017.

I'd like to note that we took January's severe weather effect on volumes, primarily in the Williston Basin, into account when setting 2017 financial expectations, the total impact of which was approximately $8 million in our gathering and processing and NGL segments. Terry will provide more details on the recovery of our volumes as well.

The process towards closing the merger transactions -- the merger transaction continues to go smoothly. We expect to close the transaction late in the second quarter or early in the third quarter. We filed our amended Form S-4 with the SEC on April 21 and are working through the SEC review process. Once the SEC declares our Form S-4 effective, both companies will mail the joint proxy statement to shareholders and unitholders for special meetings of ONEOK shareholders and ONEOK Partners' unitholders to vote on the transaction. We will communicate the timing of the meetings accordingly.

Last month, we executed a new $2.5 billion, 5-year senior unsecured revolving credit facility to replace the existing ONEOK and ONEOK Partners' credit facilities. The new facility will be available upon the closing of the merger transaction and the termination of the existing credit facilities.

Finally, first quarter results include approximately $7 million in costs associated with the proposed merger transaction, including approximately $1.1 million in costs at the partnership.

I'll now hand the call back over to Terry.

Thank you, Derek. Let's take a closer look at each of our business segments, starting with our natural gas liquids segment.

First quarter 2017 adjusted EBITDA for the segment increased 3% year-over-year and 10% compared with the fourth quarter 2016. Results benefited from increased optimization marketing from wider NGL location price differentials, increased volumes from recently connected natural gas processing plants and increased ethane recovery.

Since the first quarter, we've seen the Conway-to-Mont Belvieu NGL pricing differentials narrow slightly. However, we still anticipate a modest optimization benefit in the second quarter and expect the price differentials for the remainder of the year to be close to $0.03 per gallon for ethane.

We continue seeing the volume benefit from the 6 third-party natural gas processing plants connected to our system in 2016, and as expected, we connected 3 additional third-party plants to our system in the first quarter 2017, one each in the Permian Basin, Mid-Continent and Rocky Mountain regions. We also remain on track to connect 3 additional plants this year, including 2 plants in the Mid-Continent and 1 in the Permian Basin. The total combined NGL production of these 6 new plants is expected to ramp up to approximately 30,000 barrels per day by the end of 2017 and increase to approximately 40,000 barrels per day in 2018.

Our new NGL plant connections in 2016 and 2017, combined with increased drilling activity across our footprint due to lower breakeven costs and improved well productivity, are expected to drive NGL volume growth from the SCOOP and STACK areas, the Permian Basin and on the Bakken NGL pipeline through the remainder of 2017.

Ethane rejection levels on our NGL system decreased to an average of more than 150,000 barrels per day in the first quarter 2017 compared with an average of more than 175,000 barrels per day in the first quarter of 2016 and an average of more than 175,000 barrels per day in the fourth quarter 2016.

We continue to expect ethane throughput to increase in the second half of the year, as demand increases from 3 new petrochemical plants coming online the remainder of 2017 and capacity utilization increases at existing ethane export facilities.

Moving on to the natural gas gathering and processing segment. First quarter 2017 adjusted EBITDA increased 4% compared with the first quarter 2016, primarily driven by higher fee-based revenues from restructured contracts. The segment's average fee rate was $0.83 per MMBtu in the first quarter 2017 compared with $0.68 per MMBtu in the first quarter of 2016, a more than 20% increase. We expect the segment's average fee rate to be in the range of $0.80 to $0.85 for 2017.

Severe winter weather in January impacted first quarter volumes processed, primarily in the Williston Basin. Volumes have since recovered, with natural gas volumes processed in the Williston Basin averaging more than 800 million cubic feet per day in April, which is above our November 2016 average of approximately 780 million cubic feet per day and a new monthly average high for ONEOK in the basin.

Producer activity levels continue to increase, as there are approximately 30 drilling rigs currently operating on ONEOK's dedicated acreage in the basin, up from 20 rigs at the beginning of 2017. Recent reports show there are nearly 50 total drilling rigs operating in the Williston Basin, which means more than 60% of the rigs operating in the basin are on our dedicated acreage.

We connected 75 wells during the first quarter, and we estimate there are still approximately 300 drilled but uncompleted wells on our dedicated acreage in the basin. We currently have approximately 175 million cubic feet per day of available capacity compared with the 200 million cubic feet per day we indicated previously.

It's a similar story in the STACK and SCOOP areas with producers increasing activity and moving additional drilling rigs onto our acreage. We have approximately 12 rigs on our dedicated acreage in the Mid-Continent and expect this number to increase through the remainder of the year, as well production results have continued to improve for our producer customers.

In the natural gas pipeline segment, first quarter 2017 adjusted EBITDA increased 12% compared with the same period in 2016. The segment continues to benefit from higher fee-based earnings, driven by increased firm contracted capacity and capital growth projects recently placed into service.

In the first quarter 2017, the segment saw the benefit from operations of the ONEOK WesTex pipeline expansion and the Roadrunner Gas Transmission pipeline, including the full revenue from Phase 2 of the Roadrunner Pipeline, which was placed in service in October 2016. These projects provide additional fee-based earnings and expand the partnership's connectivity of producers in the Permian Basin with end use markets.

The segment continues to expand its operations this year with additional fee-based capital-growth projects, including the 100 million cubic feet per day westbound expansion of the ONEOK gas transmission pipeline out of the STACK and the 55 million cubic feet per day pipeline, which will provide transportation and storage services to an electric generation plant near Oklahoma City. Both projects are currently under construction, with the electric plant connection project expected to be complete in the third quarter of 2017 and the OGT expansion to be complete in the second quarter 2018.

We are actively engaged in discussions with producers for long-term natural gas takeaway solutions in the Permian Basin and the STACK and SCOOP areas. In the Permian Basin, these projects could include an expansion of our Roadrunner pipeline to provide more natural gas supply to Mexico or an expansion or extension of our ONEOK WesTex pipeline system.

In the STACK and SCOOP plays, we believe there will be a number of additional opportunities to expand our ONEOK gas transmission pipeline system to move more natural gas to on-system markets, as well as provide natural gas takeaway options out of the play.

Now more than 4 months into 2017, our visibility for the remainder of the year continues to improve. We've reaffirmed our financial guidance and continue to gain confidence in the producer and end use market activity across our footprint, as drilling rig counts continue to increase in the basins we serve and ethane demand increases.

We're excited about the remainder of the year and what's ahead for ONEOK as we approach the anticipated completion of the ONEOK and ONEOK Partners merger transaction. We have a long runway of potential growth opportunities with $1.5 billion to $2.5 billion of growth projects under development.

We are focused on executing our long-term strategy and operating as one of the country's leading midstream energy companies. Thank you to our employees for their continued hard work and dedication, and thank you to our investors for your continued support.

Before we take questions, I have one additional announcement and thank you that I'd like to extend. Yesterday, ONEOK board member, Kevin McCarthy, tendered his resignation from the Board of Directors. Due to increasing responsibilities related to his position as Chairman of the Board of Kayne Anderson Acquisition Corp., which recently completed its initial public offering, Kevin has elected to remove himself from the ONEOK Board of Directors effective immediately. Kevin has been a valued board member and key contributor to our company since joining the Board in December 2015. His deep experience in the energy industry and knowledge of the financial markets will be deeply missed. We thank him for his many contributions, the experience, wisdom and, most importantly, his friendship. We wish Kevin well in his future endeavors.

Operator, we're now ready to take questions.

(Operator Instructions)

We will take our first question today from Shneur Gershuni with UBS.

Terry, maybe I wanted to start off with -- it's almost like a 2-part question. But I was wondering if you can talk about how much spare capacity you have across the company broadly to handle growth. Or one way to measure it maybe is how much EBITDA growth can you have -- can you experience without spending any incremental capital? And the reason I ask this question is when I sort of look at your proposed CapEx for '17 and '18 and kind of compare it to your market cap and enterprise value, it seems kind of on the low side. And so I just wanted to know if we're approaching max fairly soon as to where the EBITDA growth can be? Or is there a lot of spare capacity out there? Alternatively, are there projects that you're reviewing with the Board and we can actually see that number go up? So I was just wondering if you can sort of comment on that, broadly.

Sure, I'll let -- I'll actually let Kevin take that capacity part of the question.

Yes, Shneur, we still see the available capacity. Terry referenced the 175 million a day we have in the Williston for processing. We're probably in the 75 million a day range in the Mid-Continent from a processing G&P standpoint. On the liquid side, we're still in that 30,000 to 40,000 barrels a day of capacity on the NGL system that we have to grow into. And then we've talked quite a bit about there are some expansions we can do for not a tremendous amount of incremental capital to get us up to maybe 100,000 barrels a day of incremental capacity along the NGL side.

Shneur, the only thing I'd add to Kevin's comments is that when we think about what that operating leverage provides to us from an EBITDA perspective, I think we said publicly in the past that 20% to 30% potential impact to EBITDA, assuming kind of a normalized kind of $50 barrel type pricing environment. So that gives -- that just gives you a sense of the earnings potential if we're able to take advantage of this excess capacity, which we fully expect to do.

Okay. And then as a follow-up question, I'm not sure if you saw the Enable announcement earlier today, but as I sort of look at what they announced, it seems like they're basically moving unprocessed volumes out of the basin, kind of as a synthetic takeaway solution. When I think about sort of the broader impact, I'm not processing it in the basin, I'm processing it outside of the basin, and it sort of seems like I'd be basically taking away an NGL takeaway opportunity for ONEOK. And I'm trying to understand, is that an opportunity loss and somebody else is moving it? Or is it an opportunity cost? Could we see, as they connect that some of their volumes that might have been going on your system, move further down into Texas and so forth? Wondering if you kind of have some early thoughts on that announcement.

So first comment I'll make is that I think that what that -- the announcement from Enable, yes, we're aware of it. I think what that shows you or provides you is an indication of the strength in this play and how much activity there is. I think in terms of potential impact to ONEOK, we really don't -- we don't see any -- at least given what we know of the project today, we don't see any impact to our existing business. Enable has, just like they always have, has had a very strong position across Western Oklahoma with their gathering and processing business. Well, I don't see this changing the competitive landscape. They were either going to build that processing capacity for -- on location or they were going to seek a third-party to process it for them, and that's what they've done. So I don't think that announcement, in and of itself, the access to additional capacity doesn't surprise us at all and, broadly speaking, doesn't change really the competitive landscape, which has always been competitive in the Mid-Continent.

So you're forecast didn't -- always -- your forecast didn't contemplate where they built the processing plant? Because if they built it on-site, then you would have had an opportunity to move those NGLs. And now that it's offsite, and so it's really even opportunity lost, not -- certainly not a cost, right? I mean, there's no negative impact.

That's right. It's not a cost. I'll ask Sheridan Swords. Do you have anything to add to that?

The plants that are on the ground for Enable are dedicated to us for a long period of time. So it's -- and we foresee them filling those plants and coming to us. So we see this more as an opportunity loss that's in liquids that we could have got, have moved out the basin. What I would say is we're talking too many other people right now that have a lot of liquids that will be coming to us in the future.

The other -- Shneur, the only other comment I'll make is that, obviously, if that's a path for NGLs to make it down to the Barnett Shale, and if that's some indication that Barnett Shale plants are going to be increasing their NGL production, obviously, we're in the Barnett Shale today. And certainly, as -- if NGLs materialize in the Barnett as a result of this project or any other projects, we're certainly -- we stand there ready willing and able to compete for -- compete with those -- for that business.

Okay, that makes sense. I just wanted to make sure it wasn't a negative. Just it's kind of a neutral is how it looks. Okay, perfect.

That's how it looked to us. It's not surprising. I mean, Enable needed to do something and needed to come up with some capacity to serve their specific customers, just like we have to serve our dedicated customers.

And we'll now go to the Christine Cho with Barclays.

I wanted to actually maybe start on in the Bakken. The volumes on your Bakken NGL line are approaching capacity, yet your expansion on the pipe isn't scheduled for until third quarter next year. Can you run above nameplate? And if so, by how much? And why wouldn't you accelerate the expansion to be sooner? Do you not think it's necessary? And would this also require more expansion on pipes, more downstream like Overland or Sterling beyond Sterling III?

Christine, this is Kevin. So the quick answer is yes, we do believe, in many cases, as we build assets, they can perform better than designed, and we believe the Bakken Pipeline is no different. So we have been able to operate the pipeline above the nameplate. We potentially could get to the [1 45, 1 50] range, we believe, operating safely. So we -- that's some headroom that we have. We continue to evaluate the producer activity coming out of the Williston and are accordingly looking at a variety of different options for the expansion and potentially even larger than has been -- than we've talked about previously as we can get additional commitments from the producer community up in the Williston.

Okay. That answers it. And then in the Permian, we've seen some of your peers announce a new Permian NGL pipe, while an existing one continues to expand capacity. And it seems like they're both being underpinned by the utilization of either their own processing plants and/or existing relationships with certain producers. We've seen some turnover in the acreage private equity guys sell some of the processing assets. And for one, the buyer was a customer on your West Texas line. Is the NGL takeaway for those newly acquired assets committed to somebody else already? Or is that an opportunity for you? And if you could talk some about the dynamics about what's going on in the Permian and whether or not you think being involved in processing or not being involved in processing here is a competitive disadvantage with respect to your NGL pipe.

Christine, I'll make a comment, and then I can let Kevin and Sheridan chime in. But from that question, the strategic question with respect to owning, gathering and processing assets. Certainly, if a gatherer and processor also owns a liquids pipeline in those particular scenarios, that you're going to have some challenges in competing for those particular barrels, unless those producer customers have specific taking kind rights and they've targeted a particular NGL pipeline to do business with. But overall, there's a large body of third-party, at least as far as ONEOK is concerned. The sea of third-party NGLs out there is pretty deep. And so regardless of who owns or operates the G&P business, we got a pretty big playing field in terms of opportunity and competing for barrels. So we really don't feel like we're disadvantaged. You can be in certain specific situations. Certainly, yes, it can create challenges for you. But broadly speaking, we don't feel like that we need to own G&P assets in order to be a more effective NGL service provider. No, we don't have that view. So anything -- hang on just a second, Christine. You guys have anything to add to that? Okay.

I thought maybe with respect to the private equity, Christine, didn't you have a question on the private equity barrels and whether that would create opportunity, private equity processing plants and/or opportunity?

Well, because one of them sold to a customer that is a customer on your West Texas system. And I was just curious if, was that an opportunity for you?

You guys want to make a comment?

I think we're always looking at the opportunities out there. But again, I'd go back to that specific opportunity. We don't necessarily feel that not having the G&P puts us in that competitive disadvantage in that circumstance. We're having lot of very positive conversations with producers out there that were extremely competitive. So we feel good about that.

And Christine, the only other comment I'd make is that, candidly, a number of these NGL producers or processors in this basin tend to take a look at a portfolio approach, too, in terms of their NGL service provider. So they're continually thinking about that mix and putting all their eggs in a particular basket. So that dynamic's out there, too, and from time to time, that can work to our advantage.

Okay, great. And then lastly, just a housekeeping item. In the G&P segment, your NGL sales went up to over 170,000 barrels per day after being flat at about 155,000 all of last year, despite gas gathered and processed volumes being flat from fourth quarter and generally down from first to third quarter last year. Similarly, we saw the equity condensate volumes spike up during the quarter too despite your conversion of POP contracts to more fee. So I was just curious, what's driving this?

Two different things, Christine. This is Kevin. On your first question, on the NGL sales, that was almost entirely driven by increased ethane recovery in the Mid-Continent. So that's what drove your ethane -- or excuse me, your NGL sales up. The condensate question, with the abnormally cold winter, we saw additional condensate fall out in the gathering line. So you would see the condensate go up a little bit. And what you didn't see, you'd see a corresponding NGL drop a little bit from an equity standpoint as that, that condensate didn't make it to the plant. So pretty tactical stuff.

Next is Eric Genco with Citi.

I think my first one has already been answered a little bit, but did the 25,000 barrels a day of ethane, increased acceptance, was that all Mid-Continent?

The vast majority of that was from the Mid-Continent.

Okay. And then if I just -- to jog my memory, if I think about the kind of $200 million of ethane uplift that you guys had talked to in the past and the $100 million of incremental NGL benefit from the STACK SCOOP, I'm curious as to like if you were to break that $100 million of STACK SCOOP benefit down between sort of ethane and C3 plus, how much of it is C3 plus?

Probably 55% or so.

55%, okay. So then it's not -- so there is some sort of ethane there. I guess, to follow up, if we think about sort of how things are shifting around and I think when you originally gave the $200 million marker for ethane, we were referencing kind of what rejection was on the system at the time, and there was a pretty significant amount of Bakken ethane rejection. If you were to be in a situation where Bakken ethane, from an economic standpoint, wasn't really called on, can you still get to the $200 million without cannibalizing, say, some of the ethane from SCOOP/STACK or something like that?

Yes, Eric, this is Kevin. I think what we've provided is there's about $170 million out of the $200 million that's from the Mid-Continent area. So that incremental just would be what you would have left from the Bakken.

And Ted Durbin with Goldman Sachs is next.

You've talked about this 1.4 Bcf a day project out of the Mid-Continent. But clearly, there are some competitors that are trying the same thing. I'm just wondering if you can give us an update on the project, please?

Yes, Ted, this is Kevin. We continue to work with our producers and other customers and processors in the play to look for takeaway options. Those are going well. There's some maybe specific things we're looking at, at the SCOOP and some talking to some customers that may want to go west with their gas. So we just continue to work to try to gain the commitments necessary to announce something that would be another takeaway solution out of the STACK. So again, going well, but just as we get those commitments, then we'll make the announcements.

Okay. And then I'm not sure how much you can talk about this, but you've got projections in your S-4 where you show EBITDA through 2021 or so. You're up at about $2.7 billion in the expected case. I'm wondering if you can just help us on some of the key assumptions you used to get to those projections. We know the commodity price assumptions, but are there other things around whether it's volume growth or ethane rejection or different capital that you deployed to get to those projections?

Well, so Ted, let me just make a couple of comments. As far as the S-4 projections go, one of the things I just want to make clear is that those assumptions that we made were assumptions that were made at that particular point in time. So what we don't want to do is get in a -- and we're going to talk about them, but what we don't want to do is get into a position where this becomes kind of sort of guidance, okay? So the S-4 is out there. It's public information. It's based upon the best data and our point of view at the time. Our point of view continues to be generally in line with that as what you see in the S-4, okay, good, solid fundamentals, good organic growth opportunities in the STACK and SCOOP, the ethane story, all of those things and roll into that story. What I don't want to do is get in a habit here of having to address the S-4 on just a continual -- on a continual basis, and it kind of sort of becomes, by default, a 5-year guidance, okay? I do appreciate your question, and I'm being responsive to it. It -- like again, let me say it. It encapsulates all the elements we've been talking about here, does not require any sort of major project outside of kind of an organic -- kind of a routine organic run rate of growth. Does that make sense?

Yes. Well, in part, because your organic CapEx spend has been down a bit in the last couple of years as you pulled back on projects. So you're telling us, there isn't a lot of, I don't know, new processing plants or a big gas pipeline takeaway out of the Mid-Continent in those numbers?

Exactly. You don't have any -- I call that a major strategic organic project, you really don't have in there.

I would put it more in the category of routine growth, okay? You're going to have some processing capacity. You're going to have system expansions. You're going to have plant connections on the NGL side. You may have some frac capacity increases. You're going to have some storage projects in there. But nothing that I would consider like a major geographic expansion project. So -- and what we said publicly in the past about that capital spend in that 5-year view, it's been very consistent with -- it will be consistent what you've seen in recent history from like what we've seen in 2016 and what we're budgeting here for 2017 would be, from a CapEx standpoint, what would be the consistent run rate through that 5-year view.

We'll now go to Danilo Juvane with BMO Capital markets.

Most of my questions have been hit, but I wanted to follow up on Eric's question around ethane. So I estimate roughly 300,000 barrels per day of demand. Ethylene cracker demand still coming online through the balance of the year here. As that sort of progresses through the course of the year, where do you guys ultimately see the ethane recoveries falling between the 35,000 to 55,000 barrels per day of rejection that you have projected for this year?

Sheridan?

I think what we see is we see ethane rejections, as we said, ramping up during the second half of the year as that volume comes on as -- or as that demand comes on. A lot of that demand, specifically, the CPC cracker and the Exxon mobile cracker, are going to come up in the fourth quarter. So we're going to see ramp-up through the second half of this year. Then when we get into '18, I think you'll see more sustained reject recovery across most of the Mid-Continent and Permian. And there's to be able to meet all this new demand coming on. Does that answer your question?

It does. I guess, maybe if I could ask that question differently. Do you see perhaps you following at the high-end of that range? Or how should we think about that?

That's going to be interesting. I think it's going to be very volatile as we get through this year. And don't forget about the exports coming out of the Gulf Coast as those ramp-ups well, they can have a big impact on that. But we also have -- you still have quite a bit of ethane in storage that needs to be worked off. So I think it is -- will be interesting this year. We think it will be fairly steady through the second half of this year, but it definitely could be quicker than we expected as well.

We'll go to Chris Sighinolfi with Jefferies.

Just want to ask a couple of items. On frac volumes, looking at the outlook and thinking about the comments and ethane recovery, just, I guess, if we were to ignore the change in ethane recovery year-on-year, your guidance might imply that frac volume could be down. So I'm just curious, like on the legacy business exchanges in ethane expectations, what sort of might be driving that if you or Sheridan have any -- any color on sort of that element would be appreciated.

Sheridan?

So the question is why is our frac volume down during the fourth quarter and first quarter.

No, for 2016 versus '17, particularly if I ignore any potential to frac recovered ethane.

Well, I think still as you go and look through the 2 years or so, we are going to have some opportunities if you just transport it only volume as we come out of that. We also had -- in 2016, we had quite a bit of spot volume we had in 2016 that we do not put into our expectations in 2017. There may be some opportunity for that. But overall, if you look at the base business on frac volume, we think the frac volume will increase, the C3 plus volume will increase through our fractionators if you take out the ship (inaudible). I mean, not (inaudible) but the spot volume that we had in 2016.

Okay, Got it. So there's spot volume, but from a guidance convention, not included?

Yes, we do not include spot volume in our guidance.

Understood. Okay. Wanted to also look at the delta between, I guess, this is sort of a related question, Sheridan, but the delta between the volumes you gather and the volumes you frac and particularly, the change in those numbers from the back half of last year to what we saw in the first quarter. Looks like there was a bit of a deviation where you were effectively fracking volume in advance of the volumes you gathered in the back half of last year. And now you're gathering more than you're fracking. And so just wondering if that's a temporary shift, if it's specific to something we can discuss or if it's something we should think about more on a ratable basis moving forward?

I think the big issue you have when you think about gathered volume and fracked volume and trying to tie those 2 together is storage. And that there's some, as we go in and out of quarters, we may have more or less in storage. Or specifically, as we think about the Sterling pipelines, where are we in the quarter, what line has feed on and we could actually have a lot of storage in line to those lines. So frac volumes can kind of get smeared out through the quarters, where 1 quarter, you could see gathered volume's up but frac volume is down. You'd have to go and look at our inventory, how we ended the quarter and how we exited the quarter with line fill inventory and also with our inventory in our storage wells as well. So that, I think, was the difference when you think about frac and gathered. Gathered is pretty much real-time. Frac can be -- you can see shift of volume that was gathered in 1 month and gathered in 1 quarter and frac in a subsequent quarter.

So over time, you would expect those numbers to move sort of, I guess, loosely in tandem?

That's right. Yes.

And then final question from me, Terry. You had mentioned it and obviously, flagged it on last quarter's call, but the optimization opportunity that we saw in the first quarter, you were noting in your prepared remarks an expectation for ethane differential of $0.03 for the remainder of the year. Can you just remind us if that was what was embedded in the NGL segment's EBITDA guidance or if it's changed at all? And then as you see enhanced ethane rejection -- or sorry, recovery, would it stand to reason that we should see, perhaps, a widening in that price dynamic?

I think the answer to your questions to both is yes.

Okay. So consistent across the board. Okay. Great.

Yes.

And we'll go to John Edwards with Credit Suisse.

Terry, just following up Chris's question here. Just is there a relationship between ethane recovery and that optimization spread? I mean, is there some -- do you have some kind of -- is there a correlation there that we can kind of track on that?

Yes. I think there can be. I'll make a comment, and I'll let Sheridan follow up. When I think about it, I just think about strengthening demand in the market area, which is the Gulf Coast. And of course, it depends on what your supply situation is upstream, and if you are in a situation that we are where we have lots of supply, you can see a widening of the spread when the demand pull increases, okay? So that -- and so that could then have an impact on the pricing differential between the 2 hubs. So that's kind of how I think about it in its most simplistic terms. Now the other part of the answer can get more complicated. But Sheridan, have you got anything to add there?

The only thing I would add there is that as we do increase ethane recovery, the one thing we'll see is a continuing the high utilization of the pipeline in between Conway and Belvieu, which has the potential to have a widening effect on the other products as well.

So there's not -- you can't say for every 10,000 barrels of additional recovery or utilization on those pipes between the locations, you'll add $0.0025. I'm just trying to think, is there some sort of formula there? Or is it just too complicated to make that close of an analogy there?

It's -- I mean, we've -- this is our -- we bet our careers here at ONEOK on the spread candidly. And we still have difficulty trying to forecast the spread. And so it's a difficult -- as you indicate, there are a lot of variables involved. We've tried to. We've accumulated lots of data. We can come up with general correlations. But to get as precise as what you're contemplating, very difficult to do. John, we can trend it, and that's about as good as we can probably do.

Okay. So just -- I had a question. This is on one of the guidance slides that you published. It was on your natural gas gathering and processing slide. And you indicated there that with increased well completions and rig activity, that you expected about 400 well connects this year in the Williston Basin, 75 already. So I was just running through some simple math, and maybe you can tell me where I'm wrong about this because we were thinking, okay, if you've got 30 wells out there, and you drill -- I mean, 30 rigs, and you drill a well every 2 weeks or so, 25 wells per rig for the year, multiply that, you get 750 potential wells. But you're guiding to 400. So am I wrong about the frequency or how long it takes to drill a well? Or are you going to have an increase or a buildup in DUCs? Or how should we think -- or how should I think about that? Or am I wrong about that?

John, this is Kevin. I think the assumption you're making on average is probably a little strong. We use probably more 15 wells per rig per year on average. Absolutely, if a rig is sitting there in great weather, it might be able to spit out the number of wells you're talking about per year. But on average, across the basin, with all things included, we see an average of probably more 15 wells per rig per year. So that puts you in the 450-ish range. Then you've also got to factor in the lag, right? So when these rigs show up, there will typically be several month lag between when first flow happens with the time they get completed. So that's why we still feel pretty good about our 400.

We'll go to Michael Blum with Wells Fargo.

I just had one question related it's kind of -- I guess, I sit back and it seems like all the focus is on the SCOOP STACK. But I was curious, obviously, your overall guidance didn't change. But in terms of what's going on in the Bakken, can you just provide like an update in terms of what you're seeing there in terms of activity levels and how things are trending maybe relative to how you thought it would be when you started the year? Just trying to get an update on that piece of the business.

Yes, Michael, it's Kevin. We've been extremely pleased with the activity levels we've seen over the last several months. We -- in fourth quarter, we communicated that we saw some rig increases. We've continued to see those increases up to 30 rigs and continued activity. And then Terry talked about our April volumes and where -- how they've recovered to where we're setting records. And that puts us in a great position, to me, relative to our guidance.

We'll go to Craig Shere with Tuohy Brothers.

Any update on West Texas LPG rig case and the natural expansion opportunities on the linehaul?

The rate case, we did have the hearing with the ALJ, and that process continues as we've kind of outlined before. So we're still on schedule and expect to reach a decision by the end of the year. As it comes to expansions, again, we continue to discuss with a lot of producers and other activity out there. As we get those commitments, then we'll obviously be coming forward with a project to expand the pipe.

And to the degree you're getting additional transshippers on the line, they are currently already signing up at higher rates than what the legacy customers are, right? So you actually have a kind of transparent market number right there for the ALJ. Is that correct?

Yes, we believe -- we absolutely believe that's the case.

And so that number might be closer to what, a $0.05 or something versus under $0.03?

I don't think we've disclosed that, have we? We have not provided that publicly.

Craig, this is Terry. Given the fact that we're in the midst of this case, I'm hesitant to throw some numbers out there that might create a problem for us, as you can appreciate.

Understood. Don't want to create trouble.

Exactly. That's good.

On the expansion opportunity, is this something that we see more back-end loaded in the decade? Or because of the growth in the Permian, could this really be something where we could have an announcement the next year?

I think it's much more near term than the end of the decade. Again, we're having discussions literally daily with producers and the processors that are in the basin. And it's -- you can easily point to the rig increases and the volume increases that are coming out of that to show that there's some near-term -- definitely some near-term opportunities.

And what's driving the short-term fall-off in the last couple of quarters on the line in terms of volumes?

Well, the primary reason for the drop just sequential quarter-to-quarter is we do have -- with that pipe, we have -- we continue to look for ways to optimize and integrate that pipe with other assets we have. And so we have taken the opportunity to -- we look to shift. We've shifted some volumes coming out of North Texas from the West Texas pipeline to the Arbuckle pipeline to get a feel for, as volumes grow out of the STACK and SCOOP and comes out or as volumes come out of the Permian, just looking for ways and to understand the capacities that we have on both of those pipes. So you really saw a little bit in Q1, we took the opportunity to do some of that optimization. So you saw some volume shift. We saw an increase in the Mid-Continent, and that's the primary reason why the West Texas volumes were down.

That's very helpful. And my last question, on the 1/2 of $2 billion in potential growth project opportunities, incremental opportunities, are we -- given the fact that maybe the STACK residue gas takeaway solution may not be as good an opportunity after the midship project, and with sub-$50 crude, should we be thinking more towards the low end of that range? Or do you feel there's so much in backlog that the chairs may get rearranged, but the opportunity set still in total exists?

Craig, no, I would not look at it that way. We've got more projects that we're in the process of high grading that could flow it go -- and have gone right into that backlog. So I wouldn't think about it that way at all.

And there are no other questions. I'd like to turn it back for any additional or closing remarks.

Thank you. Our quiet period for the second quarter starts when we close our books in early July and extends until earnings are released after the market closes in early August. Thanks for joining us.

And that does conclude our conference for today. I'd like to thank everyone for your participation.