Ladies and gentlemen, thank you for standing by. Good day, and welcome to the ONEOK and ONEOK Partners Third Quarter 2014 Earnings Conference Call. Today's call is being recorded. At this time, I would like to turn the conference over to your host, Mr. T.D. Eureste. Please go ahead.

Thank you, and welcome to ONEOK and ONEOK Partners third quarter 2014 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 Acts 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. Terry?

Thank you, T.D. Good morning, and thank you for joining us today and for your continued interest in investment in ONEOK and ONEOK Partners. On this conference call is Rob Martinovich, our Executive Vice President, Commercial; Wes Christensen, Senior Vice President, Operations; and Derek Reiners, our Chief Financial Officer. Also with us and available to answer your questions are Sheridan Swords, our Senior Vice President of Natural Gas Liquids; and Kevin Burdick, Vice President, Natural Gas Gathering and Processing. On this morning's call, Derek will start with a review of our financial results. Rob will review our operating results, including sequential quarter variances, give a brief NGL market update and touch on the drilling economics in the basins we operate. Wes will give an update on our capital growth projects. And finally, I'll elaborate on last week's announced acquisition of the West Texas LPG and Mesquite NGL pipelines from Chevron, and I'll have a few closing remarks. During our previous conference calls, we have shared our plans and progress for growing ONEOK and ONEOK Partners. While execution of these plans has not been without challenges, we have and will continue to execute on our key growth strategies and create value for our shareholders, unitholders and stakeholders. So in the midst of weaker commodity prices and other market uncertainties, it is important to provide some perspective on how we will approach the future by acknowledging our actions and successes of the past. As we begin our call this morning, I'd like to touch on some of our accomplishments. ONEOK Partners' 2014 adjusted EBITDA exceeded $1.14 billion in only 9 months, which is the quickest the partnership has exceeded $1 billion in its history. And we are on track to grow our distributable cash flow in 2014 by over 20% since 2013.…

Thank you, Terry, and good morning. Third quarter 2014 net income attributable to ONEOK was approximately $65 million or $0.31 per diluted share, which includes a noncash impairment charge of $76.4 million or $0.09 per diluted share attributable to ONEOK in the gathering and processing segment of ONEOK Partners. I will discuss the impairment charge of the partnership in a few moments. ONEOK is benefiting from its pure-play general partnership strategy receiving $443 million in distributions from ONEOK Partners in the 9 months of 2014, a 12% increase from the same period last year. Cash flow available for dividends for the first 9 months was $478 million, providing 1.33x coverage of the ONEOK dividend. ONEOK increased its quarterly 2014 dividend for the third quarter of 2014 by $0.015 per share to $0.59 per share, 55% higher than a year ago. Now moving on to ONEOK Partners. ONEOK Partners' third quarter net income was approximately $167 million or $0.32 per unit, which includes a noncash impairment charge of $76 million or $0.31 per unit in the natural gas gathering and processing segment. In the third quarter 2013, net income attributable the ONEOK Partners was $216 million or $0.64 per unit. In the second quarter 2013, the noncash impairment charge, which is included in equity earnings from investments resulted from the partnership's 49% equity investment in Big Horn gas gathering, a natural gas gathering system located in the coal-bed methane area of the Powder River Basin in Wyoming, where dry natural gas volumes continue to decline. Distributable cash flow was $293 million for the third quarter providing coverage of 1.05x. For the first 9 months of 2014, distributable cash flow was $863 million, providing 1.11x coverage compared with $704 million for the same period last year, providing coverage of 1.04x. Our long-term…

Thank you, Derek. Starting at ONEOK Partners, the natural gas gathering and processing segment's third quarter 2014 operating income was up 42%, compared with the third quarter 2013, due primarily to higher natural gas volume growth in the Williston Basin and Cana-Woodford Shale as a result of recently completed capital growth projects. From a sequential quarter comparison, operating income for the third quarter 2014 compared with the second quarter 2014 was up 25% due to a $21 million increase, due primarily to natural gas volume growth in the Williston Basin and Cana-Woodford Shale and a $4 million increase due to changes in contract mix, offset partially by a $3 million decrease in lower net realized prices and a $5 million increase in operating cost, primarily due to timing of materials and supplies. Volumes increased sequentially quarter-over-quarter. Natural gas gathered increased 12% and natural gas processed increased 15%. We have continued to see a significant ramp-up in natural gas volumes across our system, and we expect to see the strong growth continue through remainder of the year and into 2015, especially in the Williston Basin as improved producer drilling and recovery techniques have resulted in increased natural gas volumes from new wells with Garden Creek II operating at full capacity and Garden Creek III volumes ramping up. We have updated our hedging tables in the release. We expect to execute on more natural gas and natural gas liquids hedges for 2015 during the winter heating season. As always, we will continue to monitor the market and execute hedges when opportunities are presented. The natural gas liquids segment's third quarter 2014 operating income was up 19% compared with the third quarter 2013 due to higher margin volumes delivered to the Bakken NGL Pipeline and from new plants connected in the Mid-Continent region.…

Thank you, Rob. A quick update on our announced capital growth program. We have revised our capital growth for 2014 to $1.7 billion from $2.1 billion. This change is a result of the timing of expenditures and has no impact on the projected capital growth, project cost or scheduled completion dates. As mentioned in last week's announcement, the Garden Creek III natural gas processing plant was completed in October, 3 months ahead of schedule and on budget. We were able to utilize construction synergies with Garden Creek II to complete the facility ahead of schedule. The expansion of Bakken NGL Pipeline was completed in September and increased the pipeline's capacity to 135,000 barrels per day from 60,000 barrels per day, and the Niobrara NGL level connecting ONEOK Partners' Sage Creek natural gas processing facility to the Bakken NGL Pipeline was also completed in September. The MB-3 fractionator is expected to be completed in the fourth quarter 2014. I would like to point out we increased capital expenditures on Sterling III Pipeline and the reconfiguration of Sterling I and Sterling II Pipelines to approximately $800 million from $767 million due to higher inspection costs during winter construction and post-commissioning activities. Terry, that concludes my remarks.

Thank you, Wes. Let's discuss the strategic acquisition we announced last week, which substantially increased our operating presence in the Permian as we already have a significant position with our natural gas pipeline segment's ownership of the West Texas transmission intrastate natural gas pipeline system. With the acquisition of the West Texas LPG pipeline and the Mesquite NGL pipeline, the partnership's presence in the Permian Basin will be significantly stronger, and this acquisition will establish a new region for natural gas liquids growth. These assets will give us access to a major new NGL supply basin and increases our gathered NGL volumes by nearly 40%, pushing our total systemwide NGL gathered volumes to approximate 800,000 barrels per day. Our expectation is to significantly grow these assets and enhance their service capability and flexibility. Our current plans call for investing approximately $500 million between 2015 and 2019 with even more potential projects to come. ONEOK Partners expects to generate an adjusted EBITDA multiple of 6x to 8x between 2017 and 2020 through enhanced customer services and volume increases from pipeline capacity expansions. I should further emphasize that potential margins realized downstream from fee-based fractionation and storage services at our Mont Belvieu facilities could further enhance these multiples. Our extensive NGL operating experience and the valuable knowledge of the approximately 75 soon-to-be-new employees joining us from Chevron will enable us to realize and maximize the true potential of these assets. We'd like to welcome these employees to the ONEOK team. From a commercial standpoint, we have positive, long-term relationships with the customers served by these assets. Many are our current customers in other basins where we operate. Our existing NGL asset position in Mont Belvieu provides us the ability to offer these customers enhanced services, including fractionation and storage and opportunity that…

[Operator Instructions] And we'll take our first question from Christine Cho with Barclays.

Just on clarification on the acquisition. In yesterday's release, you say you expect the asset to eventually generate 60x, which you reiterated on the call. If I take the $800 million purchase price and the $500 million of subsequent CapEx to get to the $1.3 billion and tack on a 7x multiple, I get $185 million of EBITDA, which my common sense tells me I'm interpreting this incorrectly. So if I were to take into consideration your acquisition press release, where you say you expect to double the current EBITDA of, I'm estimating, $32 million, that's net to you guys, is that what the $500 million of CapEx will get you to? And you're expecting to spend probably a considerable amount in fractionation, processing, distribution, all things related downstream to get you to that all in 6x to 8x number by 2017, 2020? Is that -- am I thinking about that correctly?

You are partially, okay? So let me try this, and here's the piece that you're missing. When we look at the growth opportunities associated with this business or with this pipeline asset, it's going to come from primarily 3 things. We've got an existing base business that's going to have some inherent growth that is volumes behind existing plants, and new plants are going to increase as drilling continues in the Permian. Considerable portion of that volume growth does not have much capital associated with it, okay? You've got another bucket of enhanced services, and I can go into some detail about that, but basically providing more flexibility, more delivery capability and, in particular, across regions providing some packaging opportunities across regions for these customers. We expect to generate enhanced revenues from that. There's not a whole lot of capital that goes with that bucket, okay? So then that leaves you with the system expansions, where we are planning to build and construct pipeline facilities to handle new volumes, incremental volumes for shippers that need to -- that need the increased capacity. That will come at a very low multiple, okay? So when you add all these up and you look at the final result, you come to a total 6x to 8x multiple on a roughly $1.3 billion capital that's going to be spent, okay? That means, so your multiple on that -- on the total incremental revenue that's being generated here looks very, very low. And it is very low because you have a lot of revenue coming that's not going to require capital investment. I hope that helps.

Okay. Yes, that was very helpful. Can you give us a -- yes?

The last one I'm going to make is that in these numbers, there's no downstream revenue coming from fractionation and storage services, okay? Just to make that clear. That will be additive and can help that 6x to 8x multiple go even lower.

I see. Okay. That's very helpful. Can you give us a ballpark estimate on maybe a percentage of the barrels that's already going to your downstream assets tied to the volumes from the acquisition? And how much is potentially "up for grabs" at some point I'd like to see contracts roll off? Also, if you could provide average length in terms of contract. That would be helpful, too.

So I'll handle this at a high level. And what I can tell you is there's basically no volume from the system that's coming to our fractionators, okay? Very -- actually, 0, okay? So it's all up there for grabs. We don't know though what the contractual terms are from a fractionation standpoint. Certainly, by owning this pipeline asset, we're now in a position to compete for that business. And certainly, I think it'd be impractical to think we could get all of it. I'm going to say we have a good chance to get a substantial portion to that volume in our fracs, okay?

Okay. Great, that's very helpful. And then I think in the past, there has been talks about potentially converting the West Texas pipe to crude service. Is -- was this on the table for you guys at all? Or do the customer contracts on the pipe prohibit you from abandoning NGL takeaway service? Or do you see the value in keeping NGL service due to all of the other opportunities that bring to the table for you guys? Is it more valuable in keeping an NGL service versus if you were to convert it and just collect the toll on crude service?

Well, Christine, today, it certainly has more value as an NGL pipeline. However, in this day and time, you better be thinking about repurposing, okay? So it should always be in the back of your mind, is there a better application for this pipeline assets considering how valuable they are these days in the midstream space. So well, I couldn't rule that crude for a portion of the pipeline system. It is certainly something we have to be thinking about, and we do think about. But right now, we intend to operate this pipeline system as an NGL facility, primarily because of those integration and downstream opportunities.

[Operator Instructions] Moving on, we'll hear from Carl Kirst with BMO Capital.

Terry, appreciate all the color on the Permian. Maybe just came off Christine's question, though. Just trying to get a better sense, I guess, perhaps as you look at the 3 different buckets. Perhaps a bit of the ramp profile of how ultimately the 40 becomes 80 becomes 175 plus. And I ask in a sense that if the $500 million is primarily system expansions and there is ability to increase revenue and EBITDA without the expansion of capital, is that something that could potentially come in the earlier years? Or is it basically a leverage effect on the extra volume from the system expansions?

Well, Carl, what I'll tell you is, yes, we do see a potential by the time we get to 2017, of course, to have a substantial increase in EBITDA along the lines of what we initially indicated. But particularly, as you -- as we make these capital investments, which began in the 2017 time frame and moved through the 2019 time frame, we're going to see significant ramp-up in EBITDA during that period. So basically, what -- how this will look is your -- without including any downstream frac or storage synergies, your multiple is going to look about like this. In that 2017 time frame, you'll get to that 8 multiple range. And then as you move through that 2019 time frame, you'll drop to that 7 range and then move into about 2020 into that 6 range.

That's very helpful. And then maybe just sort of last question off that. Of the $500 million, is that coming from pumping expansion? Or I guess, I'm trying to kind of get a better sense of is this something where you guys are looking at the drilling and the, ultimately, the volume needs and so you go ahead and effect you, you prebuild in order to handle that capacity? Or is the $500 million something that will be associated, for instance, with new incremental contracts as a gating factor, if you will?

Well I think the last part of your question, the answer to that is yes, but I'm going to let Sheridan Swords take that question.

I think on your first part of the question, yes, we see the expansion of the pipeline will be predominantly looping of sections of the pipeline to increase its capacity, which we'll -- also we'll have to increase our pumping capacity as well. But as Terry said, we anticipate through our integrated services that we'll be contracting under long-term contracts with customers for our expanded capacity through the products.

Did that help you, Carl?

And then maybe one last question if I can, for Rob just because you were talking about the view of the NGL markets and then ethane rejection at least through 2016. And perhaps my nuance in the question is in understanding that you all will give perhaps, roll your guidance through to 2017 in December. I didn't know if the ethane rejection of that comment through 2016 was just a -- we weren't ready to look out beyond 2016. Or if that was actually a sort of a call where you expect perhaps a positive ethane frac spread in 2017?

Carl, I guess, from our standpoint, what we're tying that onto is, obviously, the beginning of those crackers coming on online in that '17 time frame. And I think, as we've said before, it's going to be lumpy as those come on and as ethane supply/demand start to balance out along with the ethane export. So our -- really, our view hasn't changed per se from that, and so that's really where we've kind of focused on.

Moving on, next, we'll go to Craig Shere with Tuohy Brothers.

I've got to tell you the additional color on that Permian acquisition now sounds extremely attractive.

Yes, we think so. We're glad we got it.

A couple ones here. Rob, can you discuss the contract changes that increased the G&P contributions sequentially? And also, it looks like 2015 NGL hedges didn't change from 2Q guidance, but the percent hedged fell. Is that a reflection of moderating ethane rejection expectation into next year or increased propane plus volumes versus prior assumptions?

Yes, increased propane plus, well I'm through your second question. With regards to the first question, could you repeat that real quick? On -- your first part was...

Changes in G&P contracts.

Yes, that was in the Williston Basin, Craig, where we had some more fee-based business come on online between the second and third quarter. That was predominantly the full amount.

Okay. And so that being fee-based, and you think that's more sustainable and growing?

We do. It is. It's -- that particular volumes coming from our Divide County system, and so as those volumes continue to ramp up and then sustain, we'll be able to maintain that benefit.

And moving on, we'll go to Chris Sighinolfi with Jefferies.

This is Corey filling in for Chris. Just a quick question on the gathering and processing revised volume guidance. It looks as though you're expecting a pretty flat run rate sequentially, but a pretty good step-up in terms of op income. Just wondering if you can kind of reconcile that for us and how should we think about that going forward?

Sure. And certainly, you can get in there and look at the -- do your own calculations kind of for our fourth quarter average and come up -- you'll see volumes are up a tick overall in the fourth quarter over third quarter. But the -- it depends on where those volumes are coming from. So we're seeing a little bit more of an increase in the Williston Basin volumes and, as a result, higher margin per unit there is leading to that increase in income.

Got it. That's helpful. And then one really quick one, if I can follow up. That asset sale you're expecting to book a $16 million gain on the pipelines, can you talk about how big that total sales size is and what type of assets you're selling there?

What we're doing, it's really 2-part. We've got some nonstrategic pad gas that we're selling, so pretty low basis there. And then we've also got a small nonstrategic piece of pipe that, again, is from the sales to value is not much more than what we're showing there. So in total, it's not like you've got a 5x of sales value going on to get that gain.

[Operator Instructions] Moving on, we'll go to John Edwards with Crédit Suisse. John D. Edwards - Crédit Suisse AG, Research Division: I'm just curious if you could just talk a little bit about in terms of the inventory of project backlog. It's obviously risen quite a bit this year. I mean, in light of the sort of volatile commodity price environment, do you think it would've been -- it would be even higher? Or maybe you could talk a little bit about that? And then my other question is what was the impact on the narrowing price differential Conway-Belvieu on the quarter and perhaps on the guidance, if you could talk about those things?

Well, John, so as we look at the backlog, okay, and I think we've provided this -- some of this color before, we look at the breakdown of that $4 billion to $5 billion backlog. Roughly 2/3 of it actually is going to be coming from the NGL segment. The rest of it coming from gathering and processing and the natural gas pipes. And, of course, much of that -- most of that NGL business is all fee-based, okay? So as I think from a broad perspective of the inflow of projects into that $4.5 billion backlog, and as we think about the $4.5 billion backlog itself, right now, we're seeing no indications and no impact on this lower commodity price environment on those plants, okay? We're seeing none, okay? So that's all still intact and still looks really good. Your second question's on the op -- did that help you? John D. Edwards - Crédit Suisse AG, Research Division: Yes, that's really helpful.

Okay, your second question on the optimization margins. It's -- when you look at the impact relative to what we guided to for the NGL segment, you have to note that ethane spreads have gone from about $0.07 a gallon in our guidance. So we actually experienced ethane spread to $0.025, $0.03, okay, for the quarter. So the impacts of the quarter relative to the quarter we guided for the NGL segments, is about -- that delta was a negative $14 million or $15 million roughly, okay? So it's pretty significant impact or pretty significant hole we have to come out off in order to have a pretty good quarter. And that's an indication of the strength of the volume growth that we're seeing in not just the NGL business, but the gathering and processing business as well.

And moving on, we'll go to Becca Followill with U.S. Capital Advisors.

First question is on the volume on West Texas LPG. If, hypothetically, you were able to get a significant amount of volumes to your own fracs, would you need to construct another frac?

We would be able to handle some of that volume in capacity from these new fracs that have been built and that are in the process of being built. For a period of time, there'll be a substantial portion of that we could handle. But then as those volumes in those fracs continue to ramp up, we would likely have to build more frac capacity. In theory, if we -- let's say we contracted all of it, certainly, we would have to build more frac capacity. And some of that incidentally is in our backlog of future growth -- unannounced backlog of future growth. [indiscernible]?

Yes, that answers it. And then on the SCOOP system that comes with that, it looks like that really doesn't really generate much EBITDA right now. Can you talk about what you see in that asset? What potentially it could do for you?

Yes, well, I mean, the first thing I could -- would tell you that's integral to the operation to that business, but I'm going to let Sheridan provide you a little more color on your question.

Becca, basically, the Mesquite pipeline's capacity is leased to the partnership, to West Texas pipeline's capacity. So it collects, say, a small lease fee from the partnership, but it is integral to the whole operation of that. If you take Mesquite away, you would drop your throughput by quite a bit. Does that answer your question?

Yes.

And next, we'll go to Michael Blum with Wells Fargo.

Just 2 more questions on the acquisition. One, just to clarify, so currently, is -- or I guess, post the closing of the deal, would you guys be a shipper on the line or is it all third-party shippers on that line? And then when you think about expanding the capacity, would you contemplate, for example, your marketing business taking some of that capacity?

Great question, Michael. And because it's such a great question, I'm going to pitch a great answer from Sheridan Swords.

Michael, currently, we do ship on this pipeline. It's not currently tied into our frac, but it is tied into Mont Belvieu fracs. But we ship out small amount, less than 10,000 barrels a day on that pipeline into our fracs. As we go forward and we're looking to the moving more volume on that, we do anticipate that our marketing affiliate will move barrels on that, especially as we offer the bundled service integration services of both transportation and fractionation and storage. That will be done through the marketing piece.

Okay. And then second question is, to get to that 6 to 8 multiple, is it strictly -- are we strictly talking about expansions and increased volumes? Or you're also assuming an increase in the tariff?

We do anticipate there'll be increased volumes on that piece. As we start talking about tariffs and rates, due to some existing confidentiality agreements and just think of the competitive nature of that question, we really can't dive into the rate structures at this time.

And our next question will come from Jeremy Tonet with JPMorgan. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: Terry, I want to go back to some of the comments you had at the beginning of the call. And I think you're talking about opportunities that could increase the 10% growth at OKE, and I was wondering if you might be willing to share some more color on the topic in general, and if that might involve lower-than-expected taxes now that the spinoff of OGS has been completed sometime. I don't know if you have better color onto what that can look like.

Well, certainly, Jeremy, I'd make a couple of comments and Derek can follow up. But yes, we do see potentially an opportunity to increase the dividend growth rate at OKE. You've got to understand, we're spending a lot of capital at OKS and certainly, that could equate to more IDR opportunity for OKE. So certainly, we'll look at that. This pure-play structure that we have in place really sets the tone and does put us in a position to maximize the cash flow to the shareholders. So certainly, as we go forward, we're going to look at that. And Derek, you got anything to add?

Well I think that's exactly right. It'll be driven primarily from OKS as OKS grows, and that will also grow distributions, particularly the IDRs at OKE. It will also provide additional depreciation deductions at OKE. So those 2 things in concert could provide some upside opportunity there.

And Jeremy, from a tax perspective, certainly, if we get some good news on bonus depreciation, for example, that could help us further increase the dividend. And you know how the process works. Our Board of Directors determines our dividend policy, and we sit down and we look at all of these factors and make that determination. And our expectations by the time we get to the December 3 Investor Day, if we have anything new to share with you at that point in time, which I suspect we will about our business in total, we will share our dividend outlook, particularly the dividend growth outlook for OKE with you. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: That all makes sense. That was all very helpful. Just one last one for me. I was wondering, as far as the M&A market is concerned, are you guys still active in looking at other incremental bolt-ons as well that potentially could expand the platform or kind of full with this [indiscernible]?

Yes, we're looking at both, Jeremy. We're looking at asset, bolt-on projects across the midstream space. Certainly, as we said before, not all of them make any sense at all and some of them are so small in scale they don't -- won't move the needle. But we are looking at those on the M&A front. It's -- there's a lot of chat around in the marketplace right now. A lot of people are thinking about consolidation. A lot of people looking at their structure. However, as we kind of sit today, the weakening in the equities markets I'm sure has got some folks, who are considering M&A opportunities, kind of perhaps pausing a bit and thinking hard about their strategies.

[Operator Instructions] We'll go to Ted Durbin with Goldman Sachs.

Maybe can you just talk a little bit more about, is there a broader strategy in the Permian here after the acquisition? Is this a precursor to investments in gathering, processing or even storage? Just talk about a broader Permian strategy, if there is one?

Sure, Ted, there definitely is. I mean, we -- certainly with that NGL position, it could create great synergies with upstream gathering and processing assets. So yes, to the extent that there are gathering and processing opportunities and in particular, those that fit well with these assets, we're going to be very interested. However -- and here's the however part, the valuations that we're seeing for certain of these gathering and processing assets in the Permian are astronomical. And so that gives us pause, and we're not going to acquire gathering and processing assets at the expense of economic discipline, okay? We're just not going to do that. I think another opportunity for us is crude. We have not only the 2,600 miles of the NGL pipelines we just acquired, but we've got hundreds and hundreds and hundreds of miles of natural gas pipelines, too, that potentially could have some other purposes, in particular, for crude. So that strategy is as a result of these assets and result of us having now kind of a wider footprint in the Permian is really going to have us looking hard at crude opportunities.

That's very helpful. Maybe if we can just come to the Bakken here. I feel like we haven't talked about that much on this call, but as you've seen the regulators turning the screws on the -- the [indiscernible] are up there to hit flaring targets, can you just give us a sense of what the outlook is for the number of new processing plants we're going to need as you look at your supply curves went up for the next few years?

Well, Ted, the short answer is we're going to need a lot more, a lot more than we have today. We have in the works enough plants to get us up to 1.2 Bcf a day. And the analysts are indicating gas production could be easily 2 Bcf a day or more. What that tells me, we need more processing plants. We've got about a 50% -- as we sit today, about a 50% market share up there, so I would expect a lot of those plants to come right underneath and right well within our footprint. So -- and we have some of that in, of course, our unannounced backlog -- and some in our unannounced backlog, okay? So yes, we see a lot of runway there and visibility into a lot more growth.

Next we'll go to Eric Genco with Citi.

I just had a quick question, maybe a clarification. I think you said earlier on the Permian acquisition that you're looking at sort of returns in the 27 time frame -- 2017 time frame of 8x; 2019, 7x. And I think you said that the bulk of the $500 million of incremental capital will be spent 2017 to 2020? But I just want to make sure I understood better. Is basically -- associated with those numbers, are you saying that -- what sort of the gross cash invested at those times?

You'll see -- of the $500 million, you'll see -- the $500 million, you'll see $200 million to $300 million spent net '17 to '19 time frame. And the balance of it spent earlier prior to 2017, okay? So that's kind of how the shape of the CapEx spend will look.

Okay. And then, I guess, just trying to understand and maybe just a point of clarification, you mentioned -- you talked about the impact of ethane rejection in the quarter. And then you mentioned sort of demand likely going up next quarter as certain plants maybe come back online. How do you really -- I mean, from a GPM perspective, I mean, how do you think about things kind of over the next year and evolving? We're still in ethane rejection, but should we think about this as being maybe one of the worst quarters for ethane rejection? Should it get a little better gradually? And how do you think about that as you figure -- the Williston Basin is a greater share of the volumes and it's richer gas. So I'm just trying to think about those dynamics.

That's kind of a mouthful in terms of question, but what I'll tell you is that I'll try to give you the kind of condensed answer. And that is, throughout 2015, we expect prices to stay relatively low. You'll see ethane prices at Belvieu probably in that low $0.20 a gallon range. So fundamentally, we're still going to be oversupplied, we're still going to reject ethane at pretty high levels. So we're going to continue to see this in the 2015 time frame, and we'll see it continue in the 2016. So we'll see this narrow spread environment. We're not going to be making a whole lot of money in terms of ethane optimization for the next 18 to 24 months. And certainly, we don't have that -- we don't -- we're not counting on it in our forward view. So ethane fundamentals, while we're seeing peak demand or strong demand of 1.2 -- 1.1 million to 1.2 million barrels per day, we're balancing the market with about 350,000 barrels per day of ethane rejection as an industry, okay? So it's all well and good, and you'll hear all these good things about the spread counts. But quite frankly, we're awash in ethane and having to reject it to balance it up. I see that -- those fundamentals continuing throughout 2015.

And gentlemen, it appears there are no further questions. I'd like to turn it back to you for any additional or closing comments.

Thank you for joining us. As Terry mentioned, the ONEOK and ONEOK Partners Analyst Conference is scheduled for Wednesday, December 3, in New York. An invitation was sent out in October. Please contact me if you've not received the invitation. Our quiet period for the fourth quarter starts when we close our books in early January and extends until earnings are released after the market closes on February 23, followed by our conference call on February 24. We'll provide details on the conference call at a later date. Thank you for joining us.

And once again, that will conclude today's conference. We'd like to thank everyone for their participation.