Good day, and welcome to the ONEOK and ONEOK Partners Second Quarter 2014 Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to T.D. Eureste. Please go ahead, sir.

Thank you, Shannon. And welcome to ONEOK and ONEOK Partners' Second 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 thanks for joining us today. On this conference call is Derek Reiners, our Chief Financial Officer, who will review our financial results. Also with me and available to answer your questions are: Rob Martinovich, our Executive Vice President of Commercial; Sheridan Swords, our Senior Vice President of Natural Gas Liquids; and Wes Christiansen, our Senior Vice President of Operations. On this morning's call, we will review our second quarter 2014 financial and operating results. I will expand on sequential variances comparing first quarter 2014 results, which were impacted by strong seasonal demand with the second quarter 2014 at the partnership. I will discuss our recently announced capital projects, which increased our capital growth program to a range of $7 billion to $7.5 billion. I'll expand on what I consider an incredible capital growth days we are entering. And then, we'll discuss our commitment to reducing natural gas flaring in North Dakota plus an NGL market and Conway-to-Mont Belvieu price differential update. Before we review our second quarter performance, I would like to briefly discuss our 2014 financial guidance. We remain confident that we will meet our 2014 financial guidance expectations and reaffirm guidance that both ONEOK and ONEOK Partners. We will continue to review our expected performance as the year progresses and make any adjustments as appropriate. Now our second quarter performance. Operating income from continuing operations attributable to ONEOK reflects higher natural gas volumes gathered, processed and sold. And higher natural gas liquids volumes sold in the natural gas gathering and processing segment as a result of recently completed capital growth projects. Second quarter 2014 results reflect the first quarter that ONEOK has operated as the pure-play general partner of ONEOK Partners. We remain committed to providing management and resources to ONEOK Partners to execute its growth strategies. Derek now will review ONEOK's and ONEOK Partners' financial highlights, and then I'll review our operating performance. Derek?

Thanks, Terry, and good morning. Second quarter 2014 net income attributable to ONEOK was approximately $62 million or $0.29 per diluted share. Income from continuing operations attributable to ONEOK was approximately $70 million or $0.33 per diluted share compared with second quarter of 2013 income from continuing operations of approximately $75 million or $0.36 per diluted share. ONEOK is benefiting from its pure-play general partnership strategy, receiving $287 million in distributions from ONEOK Partners in the 6 months of 2014, a 9% increase from the same period last year. Cash flow available for dividends for the first 6 months was $341 million providing 1.45x coverage. We're reaffirming ONEOK's cash flow available for dividends guidance range of $560 million to $640 million. ONEOK increased its quarterly 2014 dividend $0.015 per share to $0.575 per share, effective for the second quarter of 2014, resulting in an annualized cash dividend of $2.36 -- excuse me, $2.30 per share. Moving onto ONEOK Partners. ONEOK Partners' second quarter income was approximately $214 million or $0.54 per unit compared with $202 million or $0.62 per unit in the second quarter of 2013. Distributable cash flow was $272 million for the second quarter, providing coverage of 1.02x. For the first 6 months of 2014, distributable cash flow was $570 million, providing 1.14x coverage compared with $445 million for the same period last year, providing coverage of 0.99x. Our long-term annual coverage ratio target still remains at 1.05x to 1.15x. We increased our second quarter 2014 distribution to $0.76 per unit, an increase of approximately 6% from our second quarter 2013 distribution of $0.72 per unit. We also reaffirmed ONEOK Partners' 2014 net income guidance range of $975 million to $1.075 billion. Its adjusted EBITDA guidance range of $1.565 billion to $1.665 billion, and its Bcf guidance range…

Thank you, Derek. At ONEOK Partners, the natural gas gathering and processing segment second quarter 2014 operating income was up 19% compared with the second quarter 2013, due to higher natural gas volumes gathered, processed and sold, and higher natural gas liquids volumes sold, as a result of recently completed capital growth projects and higher net realized commodity prices. From a sequential quarter comparison, operating income for the second quarter 2014 compared with the first quarter 2014 was up 10%, due to a $17 million increase, due to natural gas volume growth in the Williston Basin and Western Oklahoma, offset partially by a $9 million decrease in lower net realized prices and a $7 million decrease due to changes in contract mix. The segment's operating cost decreased $6 million sequentially, primarily due to the timing of materials and supplies costs. Volumes increased sequentially quarter-over-quarter. Natural gas gathered increased 10% and natural gas processed increased 14%. We have continued to see a significant ramp-up in natural gas volumes across our systems since February, and we expect to see this strong growth continue in the second half of 2014, especially in the Williston Basin as we connect more wells to our system and as we bring our Garden Creek II and III facilities into service. Natural gas liquids segment's second quarter 2014 income was up 11% compared with the second quarter 2013, due to higher margin volumes delivered from the Bakken NGL pipeline and from new plants connected in the Mid-Continent region. From a sequential quarter comparison, operating income following strong seasonal demand of the first quarter was down 10%, due to a $40 million decrease in optimization margins, primarily from narrower Conway-to-Mont Belvieu propane location price differentials. And a $15 million decrease in marketing margins due to lower propane margins, offset…

[Operator Instructions] And we'll first go to Ted Durbin with Goldman Sachs.

Maybe just starting off in the G&P business here, and if you can just talk a little bit about the returns profile that we should be looking for. I guess, and if you look at kind of the, whether it's your guidance or where the numbers are coming for the first half of the year, at least when we do the math, it looks like the returns are not up to 5 to 7x that you've been guiding us to. So, I guess, the ramp as the capital is deployed, as the volumes of ramp-up maybe just a little more help there in terms of how we should be thinking about that.

Sure, Ted. We still, in our view, still, the economic returns on these projects are still within that 5 to 7x in our view. But certainly, you do have to think about the impact of commodity prices over the course of the last 2 or 3 years, we have seen private prices come down, already has impacted returns somewhat, but we're still within that 5 to 7x range.

And is it -- should we expect that in a year or a couple of years? Or what's the timing of when we think we hit the full run rate?

When we hit the full run rate?

Yes, exactly.

I mean, Ted, most of these plants, when we turn them on particularly Garden Creek II, Garden Creek III, and then the new process capacity that we've announced over the course of the last several months, we expect those to be full, pretty darn quick. Almost, as we start them up, they will be essentially full, day 1.

Got it. Okay, great. And then if you can just talk about, again, sticking with the G&P business, it looks like you had a little bit of a sequential drop if I look at first quarter, second quarter versus first quarter in your equity NGL barrels. Is there anything behind that? Or was it kind of -- what was the driver there?

Yes, Ted. Rob will take...

We started the Canadian Valley sort of that process in April, so as you're going through the startup there or you're going -- you're not running at full efficiencies, quite frankly, as volumes are coming on, and you're getting plants lined up, so that was the primary factor.

Got it. And then last one for me. On the 2 new plants for Demicks Lake and Knox. I guess, are these contracts going to be similar to the other ones you've had where we should consider them mostly acreage dedications? Or you started bidding at minimum volume commitments or any sort of other financial backstops on any of these projects?

They'll be very similar to contracts in the past, the acreage dedications, DOP percentage plus deed [ph] components.

And we'll take our next question from Carl Kirst with BMO Capital.

Maybe just to start, if I could, with the projects in the queue, you guys obviously continue to be active, continue to point to more projects coming in the Bakken, yet you're still kind of looking at this $3 billion to $4 billion of unannounced. So I assume new projects are kind of coming into sort of help backfill. And what I wonder is has there been any shift in characteristic as you're adding new projects to that potential backlog, is the first question. And the second is as you look at that $3 billion to $4 billion, is it possible to break down from just a rough zip code of percentage, how much of that is coming from either processing or commodity exposed infrastructure versus more fee-based infrastructure?

Well, Carl, I'll take part of this question and then I'll have to let Rob follow up with it. But yes, the characterization of the projects that are coming in to the backlog as we continue to announce are not really no different than in the past. It's all gathering and processing, it's liquids-related infrastructure. And it's in, of course, our core regions, the Bakken. We have expectations for the Niobrara or the Powder River Basin as well. But really, it's more of the same I think, the mix of the projects too from a spending standpoint have been pretty well, in the past, have been pretty well, 50-50 gathering and processing and NGLs. And I'll let Rob speak to kind of to go -- to going forward his assessment.

Sure, Carl. Step back and the only thing I'll add to what Terry said is certainly, what we're seeing in the Bakken, in the Mid-Continent Shale or some or the other shales is the newer wells are stronger than probably they were a few years ago. And so, with that, kind of, as an overall backdrop, certainly, what we're seeing is the opportunity for additional gathering and processing infrastructure in the areas be it the Bakken, the Niobrara, Oklahoma as we've demonstrated and then going forward, continuing in the Bakken. And then, from an NGL infrastructure, to support those liquids. So I'd say it's going to be, at the end of the day, maybe a little bit tilted towards the gathering and processing initially, but I think over time, it will works its way down to that 50-50.

Okay, that's helpful. And then, also, if I could ask a question on the NGL volumes and this maybe more sort of geared towards the distribution lines, but noting that second quarter was relatively flat with first quarter, despite Sterling III having come online. And so I just want to get a better sense of the nuance there. Is that from more of the fact that just kind of the narrowed differential? Or was Sterling I and II, for all intents and purposes, down for the count for second quarter as it was finishing its reconfiguration work?

Well, I'm going to let Sheridan handle that question, but the only comment I will make, my contribution is that our business is a very complicated business in terms of the way we operate it. And when Sheridan gets done talking to you about that, you'll have an even better appreciation of the complexity. Sheridan, take it away, please.

Carl, you kind of hit it on the nose. Narrow spread differential is overall, that's what's driving it. As we see spreads or prices are more in favor of the Conway market, we are moving more of the barrels up through our system to Conway, which has taken barrels away from Sterling system, than we had seen in the previous quarter. So that's really overall what's driving our system, driving the flatness in the 2 quarters that paces that -- more is just going north to the higher Conway markets.

And then last question, if I could. And this is really more on the NGL volumes gathered. And Terry, correct me if I'm wrong, I think you indicated that you guys were targeting a fourth quarter run rate in the $575 million range, did I hear that correct?

That's correct.

And so that number seems to be a little bit lower than what we were looking for initially back last December, and I just wanted to make sure I knew exactly what was driving that Delta. It was primarily just a timing of gas plants coming on? But also, I wanted to ask to the extent that you have any contract renewals at the tailgate of any of these plants, do you see any headwinds of any of those plants going a different direction and or they -- is there basically a volume at risk that we should be aware of?

Well, Carl, I'm going to take the last part of that question. I'll let Sheridan handle the first part. But the last part of the question, no. We don't have concerns, but we do remain very sensitive to the market and extremely aware of our competitions out there. And so we've been very successful competing in our area and really don't see any vulnerabilities. The one contract that you've heard us talk about a number of times in the past calls is -- we had a contract at the beginning of the year that we terminated and that was a below market, very, very low margin contract that have been in place for a number of years. And so we terminated that contract. And that's, of course, has impacted our year-over-year volumes. We haven't forgotten the question already. I think Sheridan will handle the first part of it.

Carl, as we look into the fourth quarter of this year and why we've changed our volume, it kind of comes down to a couple of things. And one is we are seeing more ethane rejection across our system and so that's having an impact on us as well. We're also seeing, as plants ramp-up, they're not ramping up quite as fast as we thought they would in certain parts of our system. But also, we are seeing some -- the volume that's not coming on is more weighted towards our lower margin volume and the volume that is coming on is more of a higher margin volume. So that's a little bit unfortunate for us that we're kind of having that mix, that there are higher-margin volumes are doing well, if not exceeding our expectations.

And we'll take our next question from Michael Blum with Wells Fargo.

A couple of questions. Just kind of maybe this is somewhat big picture, but just trying to think about fractionation utilization across your system, both in Mont Belvieu and in the MidCon. And you continue to add a lot of processing capacity in and around your system, of course, a lot of it up in the Bakken. Now I'm just wondering, does that -- should we expect that, at some point, you'll need to add another fractionator to handle all that incremental volume coming off of all those plants?

Okay, Michael, I'm going to give you the short answer and then Sheridan may give you a much longer answer, but the short answer is, yes. Do you have anything to add to that, Sheridan?

Michael, you hit it. As we bring more of these plants on, not just from our own plants or from other plants, we are looking forward to having more fractionation capacity coming online, trying to make sure we understand where the right place to put it in our system is to maximize utilization of the capacity that we have now and in the future on both our pipelines and our existing fracs. So yes, you will see if everything continues to progress, you will see more fracs come out.

Michael, one other tidbit of information, I think may be helpful is that when we look at frac utilization in an ethane rejection environment like we're in right now, you may see the total utilization percentage be well below 100%. And I'm talking about anybody that operates fracs here in the industry. It's a little bit misleading because what's not being utilized in an ethane rejection scenario is the front end of the frac. The back end of the frac may be very full, okay? And so that's one little phenomenon or a characteristic that you need to be aware of that I think will be helpful to you to take you, particularly as we're in this ethane rejection environment.

Okay, that's helpful. I appreciate it. And then back on the Sterling pipeline. Just sort of -- if you don't mind going over it again, so now that you've got I and II configured and III up and running, I mean, what's the best way for us to think about what's contracted versus what's available for optimization. Is III fully contracted or now you're using I and II for optimization, or just trying to get a feel for how those 3 lines now are going to interact.

Michael, I think the first thing you got to look at those 3 lines is working as one system. And so you have 3 different capacities that you can put the right mix of product on those lines. And with how we've configured today, we're also going to use one of those lines for raw feeds to move raw feed between the Mid-Continent and Mont Belvieu. So like when we're in certain situations where we have an ethane rejection, we don't have as much FEEP [ph] coming out of the Mid-Continent, we can put that on a smaller line and use one of the other lines for purity products or raw feed if that's what it dictates. So we'll be able to move product in between those lines to maximize capacities that we have going from Conway to Belvieu. So you kind of got to think them -- you got to think of them as a complete system, not as individual pipelines.

Okay. My last question, just any updated thoughts you have on establishing a bigger footprint in the crude markets? Obviously, you've seen one Bakken crude line get that project -- get announced. Just not necessarily asking about that particular project, but just generally your thoughts in terms of getting into the crude side of the business more?

Yes, Michael. We still are engaged in that process and still would like to establish a footprint, where it makes good sense and where it makes economic sense. The Bakken continues to be an area that we're continually prospecting for opportunity. The fact of the matter is though as you look at the crude oil landscapes, not many people want to sell or divest their crude oil assets. So those are very valuable -- they're very valuable assets to the most midstream companies. So we continue to look for logistical opportunities, storage, terminalling, pipelines, that type of thing. But of course, we, again, have to continue to weigh those investments against our alternative investments in our core areas like our Bakken gathering and processing, our Mid-Continent gathering and processing, our Mont Belvieu, Gulf Coast NGL position. So we want to be in the crude business. We are very aggressively looking for those opportunities, but certainly, we're not going to do them at the expense of economic discipline. And in particular, at the expense of investments we're making in our core areas.

We'll take our next question from John Edwards with Crédit Suisse. John D. Edwards - Crédit Suisse AG, Research Division: I just wanted to make sure I understood. You mentioned about reducing flaring in the Bakken down to, I think you said to 5% or maybe 5% to 10% level by 2020, and I'm just curious, your thoughts on how much capital do you think will be required to accomplish that in -- up in the Williston Basin there?

Well, certainly, we're going to -- it's going to take a lot of capital, as you can see. We have already announced our Demicks Lake processing plant and now we're telling you that we're going to announce, yet more capacity between now and the end of the year, pending board approval. Every time we announce these plants, they're now much larger plants than we built in the past. They're in that 200 million -- they're 200 million a day capacity range. And now, we've announced 2 of them in the last several months and you got -- from that, you've got a pretty good sense of what the capital is and the frequency associated therewith. We don't know exactly when the capacity is going to stop. That is what's happening that's making this challenging for us is that the increased density, the increased number of wells per spacing unit is increasing dramatically, seemingly quarter-by-quarter. And when you look at current density levels being at about 14, roughly 14 wells per spacing unit, that's compared to maybe 3, 4, 5 or 6 several months ago, that has a tremendous impact on your volume forecast. It makes it difficult to figure out where the top side of this thing can be. We have also heard, increased density to as many as 30-plus wells per spacing unit. Although, we've not assumed that in our economics. And certainly, we have a very large acreage dedication inventory, if you will. That is we got a lot of acres under dedication there. They're continuing to grow. So it makes that really challenging, John, I wish I could tell you an exact figure of what it's going to take to get to that point, because it may take more. If I gave you a number, I might determine 3 months from now, it's going to take a lot more. And certainly, that's a good problem to have for a midstream company. John D. Edwards - Crédit Suisse AG, Research Division: So it sounds like you're capturing a very large share in this regard. I mean, would it fair -- and you've just announced these recent projects yet, and this is to Carl's question, you've not expanded your backlog under consideration, the $3 billion to $4 billion at all, but it sounds like potentially, there's upward pressure on that. Is that the right way to think about it?

Absolutely. John D. Edwards - Crédit Suisse AG, Research Division: Okay, that's really helpful. So I guess, would it be safe to say this whole flaring issue you're talking many billions of dollars, and is it fair to say, you expect to get maybe half of that business, or just -- if you can just give us an idea share-wise how you think about it?

Sure. At least half, okay? When you look at the -- you look at our footprint within our footprint, we've got 5 million to 6 million acres that our asset footprint touches. We've got 3 million acres under dedication. When you look at kind of our share of the field within our reach, 50% is a pretty good number right now. And as we continue to put these larger processing plants in, that percentage will likely grow. John D. Edwards - Crédit Suisse AG, Research Division: Okay, that's really helpful. All right, just -- and then just switching gears. I wanted to make sure I understood your comment about, what the optimization margin expectation is now. I mean, I think back at your Analyst Day, I think you're projecting for '14, I think it was something like $0.07 and...

That's correct. John D. Edwards - Crédit Suisse AG, Research Division: And what's the expectation now?

Well, for the balance of the year, about $0.03 to $0.05 a gallon, on the ethane differential. As we look out further into 2015, 2016 timeframe, we're thinking $0.05 to $0.06, so we're tampering our thoughts on that a bit. So did that help you? John D. Edwards - Crédit Suisse AG, Research Division: Yes, that's really helpful. And then just lastly, you're speaking, and again, I think this was Carl's question, but as far as, I guess, kind of the ramp on your volumes offset by margin, how -- in terms of the return on those -- on your projects, given how I think you said you're getting more at the heavy end of the barrel where the margin is higher, so is your overall return relatively unchanged? How should we think about that?

Well, as I said earlier, in the earlier question, our returns are still within that 5 to 7x. Commodity prices have affected that particularly with these POP contracts to some extent, but they're still within that -- they're still comfortably within that range. What's happening -- what effects returns as well as margin is volume, okay? And the volumes continued to perform. We continue to build incremental gathering facilities in addition to these plants at lower cost. So I think to some extent, we've offset some of that impact from commodity pricing, lower commodity pricing. John D. Edwards - Crédit Suisse AG, Research Division: Okay, so you're -- just because the volumes are ramping a little slower because of the mix, you're not really seeing significant return erosion? You're still within your...

We're still within that range. The other thing -- the other comment I'll make, John, is when we look at the returns on these gathering and processing investments in the Bakken, you got to remember too that we're bringing NGLs down, our NGL infrastructure, okay? And what happens is sometimes, we require -- it requires incremental capital to get those NGLs to market. And sometimes, for some periods of time, it won't. So the returns that you earn collectively when you combine the gathering and processing operation with the NGL investments, you get great returns. Do you follow me?

We'll take our next question from Chris Sighinolfi with Jefferies.

I wanted to follow-up on some of the volumetric questions you made during prepared remarks. Carl asked about the fourth quarter expectation on the frac side. I wanted to touch base really quickly on your hedge percentages for NGLs came down in the last update with no real change to the absolute hedge position, so obviously, it implies some higher numbers in the back half. Just wondering how that sort of dovetails with the full year guidance that you gave for gathering and process volumes. Did you take those, did I miss it or did those figures go up?

Chris, I'm going to let Rob take that question.

Chris, yes, we are expecting, at this point, a stronger second half than we had a couple of months ago. We expect to, from a processing volume standpoint, beat our guidance. At this point in time. And so as a result, you did see the percentage hedge reduce.

And Chris, of course, obviously that percentage hedged is now in that 57% range on the NGLs, we will look for opportunities to hedge as we move through the back half of the year.

Exactly.

Well, that also brings me to the next question, Terry. Which is how do you guys think given the NGL market today across all the products, clearly taking into account what you guys have said about the light end products in the past, but how do you think about sort of the window in the '15 or even beginning to look into '16, on any of that hedging behavior. Is that -- are you finding any opportunities that are attractive at this moment in time? Or is it just going to be sort of a real-time opportunistic behavior?

Chris, it'll be opportunistic. We don't have anything right now at this 10 seconds, but yes, certainly we're looking at it every day. Hard.

Okay. And so, historically, Terry, thinking about how much you guys were hedging, is the general goal going forward is still sort of get up to those levels as we enter any given period of time? Or are you comfortable running a little bit less hedged now given your internal view of the market?

Well, we -- actually this -- as you move into the later part of the year, we get a little more comfortable with our volumes. And then so we -- so as we move into the year, our tendency -- or as we move through the year, our tendency would be to get more hedged, okay? But we're -- the market today has limited opportunities for us. And like I said -- but it can change in a hurry. And we'll continue to use this opportunistic strategy, which gravitates around a 75% hedged across the board strategy, okay? So -- and it's not -- that's not real prescriptive and hard and fast. We have at times gotten above the 75%. Like I said, as we move later into the year and get more confident in our volumes, so I hope that helps.

Yes, it does, it does. I want to switch gears, really quickly, Terry, a lot of questions on infrastructure opportunities. And obviously, we've seen additional build-out in the Bakken. You alluded to some more potentially coming with board approval by the end of the year. And so I'm just curious how we think about NGL take away capacity from the basin? Clearly, you have the NGL line today and you're doing expansion on it, but as we think out beyond that, just remind me, does that system have the capacity be expanded further? Or would we -- would additional takeaway above this expansions entail an entirely new system?

Well, Chris, the short answer is, yes. It is expandable. We've done some expansion and some expansion projects are underway. And if necessary, more to come. I'll let Sheridan talk, give you a little more color on how we would expand those facilities.

Basically, the last expansion that we did--let me back up--the first expansion, you saw we put intermediate pump stations in. The next expansion, we started loops on the pipeline, so any further expansions of the pipeline will continue to extend a loop, meaning that we're laying a line right next to the original line and tying it in, that we need more capacity, we'll continue to extend those loops to be able to get the right amount of capacity on the Bakken Pipeline.

Okay. So those adds sharing to be smaller in size, or just more incremental?

Yes. The investment will be smaller in size than building a brand-new system. Now eventually, as you extend loops, you'll have a new system when you finish them all, but you do it incrementally, a little bit at a time.

Just for -- from a numbers standpoint, were the pumps that Sheridan talked about gives us up to 135,000 barrels a day and that initial looping, up to 160,000.

All right, okay. And then the final question, Sheridan, you have talked about reconfiguration of the Sterling systems. And I just want to confirm, I think, it was my belief Sterling I was the only one capable of going south to north. Is that accurate?

That's correct.

We next move to Jeremy Tonet with JP Morgan. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: Just looking at your guidance for the year. There seems to be a strong ramp-up in second half '14 EBITDA. And I was wondering, if you could provide just a bit more granularity on what's driving the ramp on an asset basis, if that's possible with which projects? And what's the shape of that ramp could look like between 3Q and 4Q?

Well, Jeremy, I'm just going to just tell you, the short answer, it's all about volume. And Rob will give you a whole lot more color than that, I'm sure.

Let's start, I guess with -- from a pipe standpoint and just kind of go segment by segment, I mean, obviously, we had a great first quarter with regards to the maximizing our assets during the severe winter with regards to park-and-loan, as did our equity interest in northern border. And so we've been able to keep that and that segment has continued to perform well as noted in the second quarter, and we expect that to continue going forward the balance of the year. So we certainly expect to keep those gains. While G&P--while the rest of the industry got stung a little bit on the outset side of that severe weather from a volumetric standpoint, again, we're emphasizing on what we said earlier, the second half of the year with those facilities coming on early with the continued strong volumes that we're seeing in the Mid-Continent, that facilities coming on earlier in the Bakken, that's giving us pretty strong indications that overall, volumes for the year are going to be stronger than what we guided to. And as a result, that's where we're going to see the benefits in the second half of the year. And as -- so that's the G&P. So obviously, expecting both those to continue to perform strongly for the year. From an NGL standpoint, while volumes are down where we thought we would be at the beginning of the year, certainly, we don't want anyone lose sight of the great first quarter with regards to, again, maximizing our assets to get propane to the Midwest market and the other opportunities have to continue to come along. Isomerization spreads, certainly were strong this quarter. The guys are doing all the, as Terry alluded, very complicated business, but they're doing a lot of things, maximizing our system, again, to take us the opportunity where spreads are. So while volumes, overall are down, we do have some better margins that are accounted for in that volume being off, as well as some additional volumes are mitigated with take-or-pay or ship-or-pay contracts as well. So net-net, that kind of where we see the 3 segments with GMP and pipes being up and then NGL being slightly down, but overall, that's the reason that Terry commented that we are reaffirming guidance for the year. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: That's helpful. When thinking about future growth, CapEx potential, I was wondering how much of the opportunity set resides, kind of in your existing footprint in particular, the Bakken, the mid Conway, you keep having lots of nice projects materializing. And how much of a focus is there on expanding the platform into new basins or growing a position there such as the Niobrara or entering the Permian, just wondering if you could share your thoughts on that trade-off.

Well, we -- as we said before, we're continually looking for opportunity to expand our footprint work where it makes sense and where we can utilize, in particular, our existing assets to enhance any competitive advantage getting into those areas. So yes, we continued to look. The Permian, certainly, as I've said many times in the past, is an area of focus for us. It’s a target-rich environment in terms of production and it's underserved in some areas. So yes, we're going to continue to expand or at least look to expand outside our footprint. The Niobrara, of course, is one as you've mentioned, one that where things are going very well for us. We continue to contract more and more acreage dedications and enhance our contractual footprint there and the capital spending is coming. So yes, that's kind of the -- that's kind of how we look at it. Yes, we really would like to have another platform, well it be like -- whether it's for crude oil as I've mentioned before or perhaps it's gathering and processing and NGLs and in another region, perhaps the Permian, certainly, that'd be very attractive to us.

Next we'll take Craig Shere with Tuohy Brothers.

So piggybacking a little on Carl's initial growth CapEx question and a number of the others, despite the $1.1 billion of incremental growth CapEx announced in recent weeks and the implicit increase in unannounced backlog, you're not getting much respect this morning at OKS in the market. Can you give some color around the pace of the timing of this $3 billion to $4 billion of incremental announcements, besides, the Bakken processing that will likely be disclosed by year end?

Sure. I mean, I think, what we can tell you as far as that capital backlog, we haven't provided specific timing associated with it, but generally speaking, it takes a couple of years to build these -- most of these projects, these plants and these pipelines. So I think if I were trying to make a swag at it, in terms of timing associated with that capital, certainly most of it would be spent over the next couple of years.

Okay. So you think most of that $3 billion to $4 billion would be announced in the next 6 to 9 months?

Yes. It would actually be announced -- well, yes, if you -- if it's going to spend -- if the spend rate is a couple of years, it takes you a couple of years to spend it, you're probably going to announce most of these projects in the next 12 months or so. But yes, I think that's fair.

Okay, that's very helpful. And Terry, expanding on your ethane commentary and John's optimization question, the roughly $0.05 spread in outlook for '15 and '16 seems much more sober than I think what you all were talking about just last quarter. I don't know if Sheridan wants to respond to this more, but while delays in downstream projects like isomer are, obviously, having a near-term impact, what exactly are the catalyst you're seeing out 1 to 2 years that are making it a little more sober?

Well, certainly, I just at a high-level, what I can tell you is supply. Growth continues to be very strong and it's coming actually from a lot of different areas like the Eagle Ford and the Marcellus. And of course, in our core areas, the supply continues to grow. So I can -- I'll let Sheridan provide you, perhaps a bit more color, at least his thoughts on that.

Well, the other thing is, you have as is within '15, '16, you get in the end of '16 '17s, when the new big crackers come online. So you're kind of in this -- we think you're kind of in the situation you are today through those next 2 months -- next 2 years. Obviously, guys have heard some other plants that have been down longer than anticipated for both planned and unplanned outages have built ethane inventories higher than we anticipated at this time, and we think that's going to have a little bit of a drag into the next 2 years.

I think, its correct too, the other comments that I'll make is, there's been a lot of talk about ethane export facilities. And so, that the timing associated with those is not immediate. So they're still a year plus away. I think the other thing that you have working against you is the view, maybe that natural gas prices are going to stay fairly weak over this time frame, as well. So that will have a -- that will kind of have a drag down effect on your ethane prices.

Okay. That makes some sense. And, Rob, I think you mentioned how the isomerization volumes were pretty good in the quarter, obviously, in the press release, there was some nice uptick in that margin. Do you see this as a seasonal optimization benefit or something that's really kind of a sustainable trend that we can see each year?

I mean, historically, it's you would call it seasonal, Craig. I think there is some things as far as where that supply was coming from this year versus in past years, where it's been more focused on a Mid-Continent supply, so that's where we got the benefit from that standpoint.

Sheridan, you got anything to add?

Yes, we're seeing a little bit more demand this year during the, what we call the driving season in the unleaded market. That is continuing over a period of time that we haven't seen in the past. Our customers are demanding more from us out of the Mid-Continent than they have in the past. And that could continue to go forward, but we don't -- it's still a seasonal spread opportunity asset.

Fair enough. And last question, I don't know if this is just beating Bakken growth into the ground, but the implicit guidance on well-connects, I think, is like 710 in the second half versus 590 in the first half and 560 last year for the second half, if I'm doing my math right. Do you see, I mean, when you talk to your producer customers, if you're able to stay ahead of their activity, do you see this growth trend continuing without any interruption? Is there a steady-state at some point in terms of total number per quarter that we should think about?

Craig, I guess, certainly, we're into the period now where from a overall construction and specifically well-connects, July and August have historically been our industry's high watermarks. I mean, you're making a lot of hate now from that perspective. So those typically peak. And as you get into the fourth quarter and early in the first quarter, depending on whether, that tends to slow you down. So again, somewhere to the overall volume standpoint with the first quarter, severe weather that puts you a little bit behind where you thought, where you thought you might be. But at the end of the day, our well-connects aren't really ratable over the year because of just the seasons that we have. But overall, from a growth standpoint, again, when you, again, step-back from a growth, to support those volumes, they're going to be continued number of connects. Now obviously, as we go to the multi-well pads, you're laying one well in and as Terry said, as those number of wells per spacing unit continue to increase, you're going to benefit from that. But at the end of the day, the number of wells ultimately, that you're able to handle is going to continue to grow because that's supporting this ultimate volume growth that you're seeing from third parties that's just continuing to ramp up to the right pretty strong.

We'll take our next question from Helen Ryoo with Barclays.

A couple of questions. Starting with the new Bakken project. It looks like the cost is like 80% of the plant is 80% higher than the Knox plant, although the related infrastructure cost is pretty much consistent and just wondering the higher construction cost for the plant, does this reflect maybe cost inflation in that area? And then as a follow-up to that is, if it's more expensive to build a G&P system up in Bakken versus other region, are midstream operators in general, able to charge more to compensate for the sort of the high-cost up there?

Helen, I'm going to let Wesley Christensen answer that question.

We have seen some upward pressure for cost for building plants and infrastructure in the Bakken area. It's primarily related to labor cost, that's have escalated in the area. As far as it goes with the equipment and supply associated with it, we're not seeing upward pressure as much on that, but we are seeing some scheduled impacts.

And then, Helen, from a standpoint of margins, I mean, margins in the Bakken are stronger than the Mid-Continent. I don't want to say that, that's necessarily the reason for the cost that you charge more, but I mean, historically, they have been stronger.

I guess, one thing I'll add to this, Wes, you could add to it if you don't hear -- if you don't agree with what I'm saying. If you look at a plant, you build a 200 million a day plant in the Bakken versus a 200 million a day plant in Oklahoma, those are not the same plants, okay? The processing plant in the Bakken is designed to operate in extremely hostile conditions. And so, a lot of measures have to be taken in the design of that plant, okay? So I mean, that's a factor in the difference of some of these costs. And, of course, the richness of the gas is hugely significant in the design of these plants. It's basically, the NGL content sets the size of many of these towers that are used in the processing and facilities, so -- and the size of liquid pumps and what have you. Whether it's getting near to that.

That's true, Terry, that's true. And they're also -- there is additional infrastructure related to stabilizers and handling the inlet condensate because of the richness as well.

And ladies and gentlemen, it appears that does conclude today's question-and-answer session. I would like to turn the conference over back to Mr. Eureste, for closing remarks.

Thanks for joining us. Our quiet period for the third quarter starts when we close our books in early October and extends until earnings are released after market closes on November 4, followed by a conference call on November 5. We'll provide details in the conference call at a later date. I'll be available throughout the day to answer your follow-up questions. Thank you for joining us and have a great day.

And ladies and gentlemen, that does conclude today's conference. We do thank you for your participation. You may now disconnect. Have a great rest of your day.