Please stand-by, we are about to begin. Good day, and welcome to the ONEOK and ONEOK Partners Second Quarter 2016 Earnings Call. Today’s conference is being recorded. 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’ second quarter 2016 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 today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners. On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, Senior Vice President and Chief Financial Officer; and Senior Vice Presidents; Wes Christensen, Operations; Sheridan Swords, Natural Gas Liquids; Kevin Burdick, Natural Gas Gathering and Processing; and Phill May, Natural Gas Pipelines. Before I hand the call over to Derek for the financial review, I will open with a few remarks. And after Derek's comments, I will discuss the segments performance and have some closing comments. We continue to like the progress we have made in the first half of the year towards achieving our 2016 financial goals at ONEOK and ONEOK Partners. Our geographically diverse assets located in the Williston, Mid-Continent, Permian, and Gulf Coast are meeting our customers’ needs by enhancing both supply and market connectivity. The asset footprint we’ve developed over the last decade has generated significant value to our stakeholders. To put the scale of investment and return to our stakeholders into a little perspective, since 2006 we have spent more than $9 billion in growth capital projects and acquisitions. In 2006, ONEOK Partners’ adjusted EBITDA was $615 million and distributions declared in 2006 were $1.80 per unit split adjusted. The partnerships 2016 adjusted EBITDA guidance is $1.88 billion and we expect distributions declared of $3.16 per unit in 2016. This impressive earnings growth with the partnership has also benefited ONEOK. In 2006, distributions declared for ONEOK’s limited and general partner interests in ONEOK Partners totaled approximately $145 million, compared with ONEOK’s 2016 guidance of approximately $790 million in distributions declared from the partnership. I would add we have prudently managed ONEOK and…

Thank you, Terry. Starting at the partnership, second quarter 2016 adjusted EBITDA increased 3% from the first quarter 2016, resulting from an increase in natural gas liquids volumes gathered in fractionated and higher average fee rates in the gathering and processing segment. Even in this lower commodity price environment, the partnerships’ year-to-date adjusted EBITDA of $900 million is nearly $200 million more than in the same period in 2015. Last year's earnings were weighted more to the second half of the year, but to Terry’s points, our assets continue to produce solid earnings in a very challenging pricing environment and we have significant room to increase our earnings with available system capacity. Our distribution coverage ratio increased to 1.15 times in the second quarter and 1.11 times year-to-date. This includes a one-time benefit from the change in the timing of cash distributions received from the partnerships’ equity method investment in northern border pipeline. Beginning in the second quarter, cash distributions related to the partnerships’ 50% interest in the pipeline are received monthly instead of quarterly. This one-time $15 million cash increase to distributable cash flow were approximately 0.07 times to coverage. Excluding this benefit, our distribution coverage ratio still continued to improve. The second quarter of 2016 represents the fifth quarter of consecutive increases in distribution coverage with our third consecutive quarter above 1.0 times. We continued deleveraging the partnerships’ already strong balance sheet as trailing 12 months GAAP debt to EBITDA improved again to 4.4 times at June 30. We continue to expect a leverage of 4.2 times or less for the full-year of 2016. The partnership has ample liquidity with more than $1.8 billion of capacity on its $2.4 billion credit facility. On a standalone basis, ONEOK ended the first quarter with nearly $180 million of cash and…

Thank you, Derek. Let’s take a closer look at each of our business segments. Our Natural Gas Liquids segment continues to be a key driver of fee based growth for the partnership. We recorded NGL gathered and fractionated volume growth across the segment’s footprint driven by recently connected natural gas processing plants and increased ethane recovery in the Mid-Continent. The ethane opportunity remains a strong expected tailwind for ONEOK Partners. Our processing plant customers connected to our system averaged approximately 150,000 barrels per day of ethane rejection in the second, down from approximately 175,000 barrels per day in the first quarter of 2016. However, a portion of the fees associated with the increased volumes were previously being earned under contracts with minimum volume obligations, we expect ethane recovery levels to continue to fluctuate for the remainder of 2016. We continue to expect a meaningful impact from the ethane opportunity beginning in early 2017 and expect $200 million in annual impact to the segment wants in for ethane recovery. In addition to the ethane opportunity, the growing STACK and SCOOP plays in Oklahoma present an opportunity for Natural Gas Liquids volume growth as we remain a critical NGL takeaway provider in the area. Based on the conversations we’ve had with producer customers in the STACK and SCOOP plays and with the results they are seeing, we expect to gather an incremental 100,000 barrels per day of Natural Gas Liquids from the play. Our current gathering system capacity can handle the Natural Gas Liquids, out of the Mid-Continent when the region is in full ethane recovery, and we expect to have available gathering capacity of approximately 40,000 barrels per day at full ethane recovery. We can expand by an additional 60,000 barrels per day, with capital expenditures of less than $100 million…

Thank you. [Operator Instructions] And we will take our first question from Shneur Gershuni with UBS.

Hi, good morning guys.

Good morning.

Just a quick operational question and a big picture question, you know you had some interesting color about the Bakken, had the weather issues not been there you would have been in line with your first quarter, so when we think about the guidance that you sort of said at the beginning of the year, how would you say volumes are tracking versus plan and then when we think about a few rigs being added into the basin increasing completion crews I think it was announced by widening the other day as well too, how should we be thinking about the exit rate for the Bakken, do you think it will be higher than what you originally planning on in the original budget and then in contrast if you can talk about I guess a little bit more in doubt about producer completion plans in the Mid-Continent, does that change your exit rate there as well to, just wondering if you can give us a little bit more color on that.

Sure this is Kevin, if we talk about Williston first, yeah I think the volumes are progressing very much as we anticipated coming into the year. We have had some producers announce some bringing some crews back and we do have that factored in. The weather and the facility maintenance we saw basically the minor decline in the second quarter. We are kind of flat right now as we move in, we have got Bear Creek which is now - say will be completed in August so we will see an extra 30 million to 40 million a day coming in when that plant comes online. Then towards the back half of the year, you know we are looking flattish type volumes as we go through the end of 2016. With the completion activity in the rigs that we currently have kind of on the schedule. If we transition to the mid-continent, little bit different story, we absolutely expect a back half waiting especially towards the end of the year as so of the large fab; the completions were delayed to the fourth quarter. So from that stand point, we do expect a ramp there and we have also had some gathered only volumes that have dropped off a little more than we anticipated coming into the year. But that’s kind of how we see the mid-continent volumes shaped up through the end of the year.

This is Terry, Kevin and it is fair to say that we are seeing a lot of activity in the stack, and predict the feedback that we are getting from producers has been really remarkable. And so if you have got any other comments you have to say about the discussions you are having with producers.

Yes, again the information I have seen come up so far this quarter and conversations we are having with our producers. The tight curves continue to improve. There has been couple of announcements already. The producers have strengthened tight curves in the area. We have seen results that have been quite impressive and a lot of the analysts are now talking it as one of the top place in the basin. We have about 200,000 acres of dedication in the stack. So we are very positive and bullish on what we expect through the - especially in the fourth quarter. It is just getting these completions on these pads done, most likely in the fourth quarter.

I guess a bigger picture question, when I looked at one of your opening slides, I think slide four, you sort of highlight the $9 billion of capital that you spend. When I think about in contrast with the OKS guide of just under $1.9 billion in EBITDA for this year. You have talked about $200 million worth of upside with respect to ethane in the near future, taking us over to $2 billion. I guess is that really a guidance quotient per say but in a more constructive commodity environment I am not talking peak oil but a constructive environment, how much operating levers does all this capital represent, you know could it would be another 10% - 20% higher at a more normalized commodity environment. I wonder if you can sort of give us a little color about your operating leverage.

Sure, so we think about that operating leverage in the capacity that we have available. When we think about our business, the capacity that we have available are certainly in the most active basins. Not just from a GMP prospect but also from NGL perspective where we have capacity and are in the good spot candidly. So when you think about more constructive environment say maybe $55 to $65 a barrel of oil environment, we are well positioned to capture more opportunities. So if you think about the impact from EBITDA perspective or the incremental EBIDTA I think 10% to 20% improvement if all those things happen. I think would actually be conservative. So I think we could outperform that considerably.

Great thank you very much guys. I’ll jump back in the queue.

And our next question will come from Eric Genco with Citi.

Hi good morning. Just want to touch real quick on the NGL segment; I was hoping you could expand a little bit about the MBCs that were absorbed by the increased ethane volume. I didn’t realize the MBCs were like significant pieces just wondering if you could tell on what parts of the system have the MBCs associated with or escalating in. Just want to make sure that doesn’t impact in any way the $200 million benefit that you had talked to in terms of going to fall I think recovery.

Eric this is Sheridan, when we looked at the $200 million up lift from ethane recovery we took into consideration in the MBCs. But also the decrease in MBCs that you saw in the second quarter was not just from ethane, it was also from an increase in C3 plus volume we are getting from the added plant that were coming online. So it is not apples and apples when you compared that, but the big thins is $200 million took into account what we have in MBCs, there is already being captured.

Okay and what part of the system do you have been, can you -

We really have some across the whole system but most of this probably in the mid-continent.

Okay and I think also in the press release you referenced there were some benefit in the Bakken from increases that made recoveries. I think that search in the crack was wide enough lot of Bakken except, can I read that correctly or what’s going on there, just in sort of discounting, sort of competitive there, just wondering if you could stop there?

We did see some more ethane recovery in the Bakken, but it was minor so less than 3,000 barrels a day and still it is all wrapped around this quality issue but we have a little bit of change but I think more on Kevin’s plan trying to keep it on the minimum level what they need to be that quality and it will bounce around little bit.

Okay, all right. Thank you very much.

And our next question will come from Christine Cho with Barclays

Hi, everyone, so I wanted to start on your stacks group comment. Terry I think you said you have the opportunity to gather 100,000 mmbtu per day, what is the time frame on this and I noticed that you didn’t say processing either so is it just gather only contract and also if you could just reiterate your comments about how you have already capacity to handle the huge volumes.

Okay Christine first thing, the number 100,000 barrels per day.

I’m sorry.

Yes we are talking primarily about gathering system capacity that is NGL gathering system capacity, once we make that comment.

Okay.

Sheridan anything you can share.

In terms of fractionation, we think first 40,000 barrels a day we would have fractionation capacity for when we expand the next 60,000 we think there is capacity in Mont Belvieu with other fractionators that handle that. If it wants we would be more willing to build our fractionation capacity and expand for that as we go forward but.

Okay, great. And then I thought the first quarter fee based trade in GNP, what is the run rate to go off I think, you kind of guided us towards last quarter so, what happens in second quarter that drew those rate higher and I noticed that your implied equity volumes didn’t look like it got smaller, so I need any clarification with overall.

Christine, this is Kevin. Yes when we talked about the first quarter we did say that we expected, we were for the most part thought we have seen the peak of the increases. We did see some again some improvement in the fee rate, that is primarily driven from just a mix of our where the volumes are coming. Each quarter the volumes will have - it will grow in some areas and decline in other areas and just depending on the types of contracts those volumes are growing or declining, will move that fee right around. So in this case we had additional volumes show up on contracts that it had been previously restructured that had a higher fee rate, some of the declining volumes were occurring on the contracts that had a lower fee rates. In addition we continue to just as part of our normal commercial activities as contracts come up with the term and so forth we work with our producers to again try to remove as much risk out of our businesses as possible and continue to convert and move the contracts to more fee based contracts.

I see and then on the restructuring, are they still mostly happening in the Bakken and then how much of the Bakken can still be restructured meaning you know what percentage of the volumes haven't been converted yet?

You know that it's occurring all over our system, so we don’t just limit it to the Bakken, as we think about moving in and you know driving to a more fee-based structure, is getting into the specifics of how much remains, I don't know that I want to talk about that, we will just continue to work that in due course.

You know Christine, I guess, this is Terry. I would add that when we set out in the Williston Basin with this objective to restructure these contracts, there were some fairly large contracts that were already heavily fee based that we felt like we could and we did, and we left those contracts alone, we were satisfied with those. So those contracts still remain. But I think for the most part I think we've accomplished what we set out to do. I would not anticipate a whole lot more contract renegotiation happening obviously until - now some of these contracts come up to term many years down the road. So I think for the most part we’ve accomplished what we set out to do, for the ongoing perspective we will stay focused in particular in the Mid-Continent to restructure where we can understanding that the challenge there is that the contracts are much smaller, there's not a lot of large volume contracts and it's a bit more tedious work and of course more challenging, more challenging environment.

Okay, thank you and then last question from me, how much NVC are you still collecting right now in the NGL business, dollar wise or volumes or whatever you can give would be helpful?

Christine, we’d not disclose that information, not going to disclose it here.

Okay, great. Thank you.

And our next question will come from Tom Abrams from Morgan Stanley.

Thanks. Just thinking about Oklahoma and the SCOOP-STACK and the excitement building there, is there any buzz that we get out of the Cana-Woodford, is that additive to the SCOOP-STACK thought processes, or is it operationally separate?

Tom, this is Kevin. I guess when I talk about the STACK, we’d roll in, I mean the Cana is right there with it. So as we think about our gathering system and our processing capacity, we kind of we pull those two together.

Okay, fair. And then with all that [indiscernible] excitement is going to move up the need for some residual gas takeaway, when does the industry need to commit to a project and I guess really when can we, would it be Roadrunner 3. How would you guys play?

Let Phillip May handle this question.

Yeah we are actively in conversations with the producers about the issue and frankly have been for a couple of years, commodity prices coming off a year or so ago, kind of dampened that discussion but it's ramping up pretty rapidly right now. We have a pretty extensive interest rate system in Oklahoma that access somewhat of a super system, so we're very attractive to some of those producers from a residue takeaway perspective. But we do get to a point where we exhaust all of our available capacity and we're going to have to build a project and we've got a couple things that we're talking about right now to several of those producers. So I think it's sooner rather than later.

The only thing I would add to that is that, if you think about your question relating to Roadrunner, many of these producers in here in Oklahoma understand what Roadrunner means to producers up in this region and many of them would like to have access to that pipeline and get access to those markets in Mexico, so they're thinking broadly about where they can get their gas and access to those markets in Mexico and certainly it could like with the WesTex project it could other projects similar to Roadrunner or related to Roadrunner could develop as a result of that high level of interest in producers who wanted to get to markets in Mexico.

And just lastly, could you remind us of your debt to EBITDA comfort zone or target. How much you might want to drift below that temporarily if you're waiting for a project like this to be to come in?

Sure, this is Derek. We finished June 30 about 4.4 times debt to EBITDA on a trailing 12-month basis, I think if you look at that on a run rate it's closer to, it's around 4.2. Our target is to get that below four times and obviously we've been taking steps to actively make that happen. So obviously we've got capital in our forecast and so we'll factor that all and that's still headed towards the four times or less.

Thanks.

And our next question will come from Danilo Juvane with BMO Capital Markets.

Thanks. As an extension of the question from [indiscernible], you guys have met your budget for the year thus far. If you continue to do so what are expectations for the resumption of dividend growth and distribution growth that OKS has and how much is your leverage target sort of playing out that that decision?

As far as dividend and distribution growth goes it's still early. We continue to assess the markets, you know the markets have backed up a bit here as of late. We're not out of the woods yet as an industry. So we're going to continue to try to carry that coverage we're building coverage that at OKS and getting it really gotten some good traction there. We hate to back up on that prematurely so as we move into the planning phase here in late 2016, and put together our forecast and guidance for 2017, we will certainly assess and there is a possibility of increases in the distribution in the dividend. But candidly at this point in time we like where we are right now. I think it's prudent to manage it the way we've been doing it.

Alright, the follow-up to that, if you post it at the end of the year and you are still targeting if not modestly exceeding your budget, would that put you in a position to consider an increase at that point or I guess what else would you be looking for - on the end of the year?

Well okay, so let me just reiterate we get to the end of the year through our planning phase, we're going to sit down with our Board and we're going to - we will assess our cash needs and make a decision at that particular point in time and certainly when we roll out you'll know exactly what our plans are.

Great thank you.

And our next question will come from John Edwards with Credit Suisse.

Yeah, good morning and congrats on a nice quarter, just Terry could, I mean you made some comments about ethane recoveries, I mean and I think you said it was like 3000 barrels a day or so, so not a whole lot here in the first and second quarter, but as we're moving here into the second half, I mean in terms of incremental ethane recovery volumes, what do you think you're going to be seeing at this point and then obviously you've put on some slides out there where you're expecting a pretty large increase in 2017, so maybe if you could just a little more color on the trajectory would be great?

Sure, I will let Sheri to tackle that question.

John, we did see increased ethane recovery in the second quarter but as the price have slid and spread between ethane and natural gas have compressed, we are back down into the 175,000 to 200,000 barrels a day of ethane being rejected across our system today and really we expect that ethane recovery in rejection will kind of inadvertently go in and out as we finish the rest of the year, but we don't expect a whole lot more of ethane recovery to the rest of this year. As we get into 2017, we think that we will gradually come out of ethane rejection as we first quarter 2017 in the Mid-Continent and we'll probably end up the end of the year being about half - into 2017 being about half what we are today.

Okay, all right so somewhere in the kind of 80,000- 90,000 range of additional recovery is I guess is a fair number.

Yes.

Okay, all right and then you were talking a little bit I think to it was Christine's question as far as any additional upside from restructurings. I mean and I know you don't really want to talk too much about or quantify it in some way. I mean can you say that you know directionally at least you are expected to be higher, I mean could you at least give us that much as far as that goes?

Yes. I think directionally we would expect it to continue to creep up but I don’t - again I don’t know, I don’t expect that you are going to see the sizable increases we have seen over the previous couple quarters.

Okay, alright. That’s helpful, that’s it from me. Thank you.

Thank you.

And our next question will come from Jeremy Tonet with JPMorgan.

Good morning.

Good morning, Jeremy.

Yeah, it’s Chris on for Jeremy. The first question is on JMP fee based margins, you’ve talked about them in the first half of this year, so when we were thinking about the second half, so to what degree could contract restructuring benefit the second half of the year and also how much of a mixed shift could that - could impact results in the second half as well.

Kevin, you want to reiterate.

When we talked about, we have seen the uptick in the first half, as we think about it in the second half of the year, I would think about it kind of where we are at just a slight increase maybe as we go to the rest of the year.

Got it. And then in terms of the contract restructuring thus far, what kind of, you see where we are in, in terms of the existing, are you current expectation and then also in terms of your efforts thus far what’s been your success rate with customer’s internal feedback at large?

Again as I and Terry has talked about, when we set out in 2015, we have accomplished almost everything we set out to do. So we are well into the game, and we will continue as we have opportunities going forward.

Great, and then let’s move on to asset recovery, you guys mentioned, you have seen some ethane recovery, but at the same time, it’s kind of an offset by those NVCs, so I was wondering what part of the system is exact on the fraction ration in NGL pipes, any color there would be helpful.

Yeah I mean most of the ethane recoveries we have seen have come out of our Mid-Continent volume, and some of it’s been on transportation element, and some of that you have seen come out of the frac space, unless they [indiscernible], and today that ethane has gone back to rejections, we were back to where we were at the start of the year, between 175,000 to 200,000 barrels a day on the system.

And when we think about the cadence going in at 2017, I guess to what extent are those NVC is going to impact potential uplift?

Well, the 200 million, when we said we had a $200 million uplift, when all of that comes down, we took in to account the NVCs when we stated that number.

Got it, that’s helpful and last one from me, on the Roadrunner you guys were ahead of your schedule for 4Q ‘16, what’s driving the earlier than expected start-up date?

Well candidly, we have done a great job in construction, and we have got great contractors out there, getting the work done, we had the benefit of weather. I think as I said in my comments, we actually expected to encounter some difficult conditions in the way of rock, and we have just not encountered those conditions, so it’s just gone very well, and accordingly we are ahead of schedule and revising our completion date.

Alright, thanks a lot guys.

You bet, thank you.

And our next question will come from Craig Shere with Tuohy Brothers.

Good morning.

Hi Craig.

I know that you didn't want to get into how much remains on the NVCs, that’s covered by existing volumes, but perhaps you could help us with getting a sense for when you expect ethane recovery to start or meaningfully hitting the bottom line, is it a first half type situation or to really feel some of the stronger Mid-Continent benefits next year or it's really more second half.

Well what I would say is we think that we will ramp up the Mid-Continent volume that goes to Belvieu in the first half, 2017 more weighted towards the latter part of the first half. And then the second half is where you'll get a little bit more the Mid-Continent, maybe they will have a common pricing out of it. So you would say you would see most of it weighted towards the second half, but you will start seeing meaningful impact in the first half of 2017.

Okay, great. And another question is about the dividend distribution policy, like I know it's a dynamic market, I know we got to wait, you'll be in your planning phase some months, as we move towards the end of the year, but you normally have annual dividend distribution policy and we're in a very dynamic market and you've already commented how you're in the catbird seat to take advantage of recovering markets once they stabilize. If we're in mid-2017 and all of a sudden things are looking better, producer activity is changing, could you call an audible and make a mid-year adjustment?

Certainly we could, and we look at it every quarter, and we examine it, and then spend as you would expect a robust amount of time talking about our dividend and distribution policies with the two companies. So it's entirely possible that if the conditions in our point of view change or improve dramatically, certainly we would consider it.

Okay, great. And last quarter, there were some comments about an attractive situation for cost reduction opportunities. I know that we had a bit of a sequential increase in quarterly OpEx, but some of that was partly due to timing issues. Can you elaborate about ongoing prospects for both corporate overhead, OpEx, cost containment in this market environment?

Well. So you know broadly speaking the low hanging fruit in terms of cost containment or cost reduction opportunities is really attributable to reduced contractor cost that is the market and the rates associated with the services that we hire out, had reduced dramatically and they continue to soften. So that’s probably the lion share of the cost benefits. Certainly we are working to try operator assets efficiently and try and find ways to reduce maintenance cost in other ways in just the market, and we’ve had some success in doing that, but I think in the first quarter I think generally speaking, we were talking more in the order of what’s the market giving us in terms of reduced rates.

Okay, do you see any ongoing opportunity there or we’ve already kind of…

Probably, the lowest hanging fruit has already been picked, but we continue to apply pressure. And there continues to be fallout and adjustments in the third party service arena and we're constantly looking for opportunities to get you know better rates and lower costs from our suppliers and vendors, there's still opportunity out there although it's slowing.

Okay, great, and last question, I'm sorry, it was probably in the prepared comments, but what was the spot volumes in the quarter again?

For NGLs?

Yes.

I don’t think we provided that number but, Sheridan do you want -

It’s about 8000 barrels.

Okay, great. Thank you.

And our next question will come from Chris Sighinolfi with Jefferies.

Hey Terry.

Hey Chris, how you are doing?

I'm good, I'm good thanks. Nice work on that continued improvement in the gathering fee and I appreciate the dialogue around the role in the mix shift, we were curious about that ourselves. I'm just curious, I guess with regard to the ongoing re-contracting effort itself and realizing you know that the bulk of those identified opportunities have already been done, but I'm just wondering if there is any change in producer acceptance of that effort. You know I ask it because there was at Williston Basin, producer who this quarter disclosed that it’s initiated arbitration for seatings with its midstream provider because it was unwilling to do a move to fee and so I am just wondering if that's indicative of anything or if that’s anything you've seen.

Well I won't make any comments about the producer, but what I will say is that with nearly all the producers we've dealt with all have understood the story and the rationale. They understood why our contracts had certain provisions in them that allowed this to happen or allowed the renegotiation to happen. They understood the need. They understood the requirement that we continue to need to be incentivized to invest capital in these areas. I think all the producers got it. None of them really - none of them liked it, but they understood the reality. They certainly did not want us to pick up and invest capital elsewhere. They needed capital to continue to be invested; they needed the services in order to monetize their reserves and continue to produce their crude oil candidly in the basin. So they all understood the rationale and as I said before, it was a long process, one that was carefully, we were very careful on the discussion with the producers, and patient and very open.

Okay thanks.

Does that help you?

It does, yeah, we haven’t seen any issue like that, and then we started this one last quarter, so I was just curious if that signal just shifted, it seems like it maybe just an one-off situation. So I appreciate just the clarification on that. Switching gears a little bit, maybe that’s a question for Sheridan, but wondering in your ethane outlook, how much switching that you guys are encouraged by the crackers, I think earlier in the Q&A dialog you talked about beginning to move more ethane towards the first half of 2017. I’m just wondering what has taken there with regard to - effectively the feedstock ability on the cracking fleet, there was an assumption or if there is just a general way to think about that.

When you say switching, switching feeds to propane.

Yeah exactly.

Cracking propane instead of ethane, you know our view always has been and we still understand that most of these crackers only can crack at bay, okay there is few that have the capability to switch and I think there's been perhaps some, I don’t know if it's confusion or what, the information hasn't been real clear, but we talk to these petro chemical companies all the time and we have a very good understanding of what they can and can't do and Sheridan, actually I’ll let Sheridan -

And we think that there's a switching capability that the crackers can consume somewhere around 500,000 barrels a day of propane, which we are doing about 400,000 today. So there's not a whole lot more switching capability. As Terry said, the new crackers that are coming online the big crackers all except for Dow are ethane only crackers and Dow has some flexibility and it's not - none of these are it's not a full flexibility, but they can't consume a little bit more, switch a little bit in between propane and ethane, but mostly everything is coming on and all the expansions are ethane only.

Right, so switching that we have focused on would obviously be on the legacy fleet, but if there's a pickup and I think demand from the new end services, if prices are warranted not - not a totally crazy scenario that there might be some loss on the legacy fleet?

Right.

But your point is as you look at it you think at most that would be about 100,000 barrels a day?

Right.

Okay, all right well thanks a lot guys. I appreciate the color.

Thanks Chris.

[Operator Instructions] Our next will come from Michael Blum with Wells Fargo.

Hey everyone.

Hey Michael.

Just on the, I guess this is one question, the uptick in NGL optimization and marketing, can you just kind of talk about what's driving that and I guess not expecting you to give us the secret sauce, but just kind of what type of metrics can we look out from the outside to sort of try to predict a little better how that business will trend.

Sheridan, you got any sauce?

Yeah, there is a secret sauce. But Michael when I look at it, as when you look at optimization the big thing you want to look at is you want to look at the spreads on all five products between Conway and Belvieu, and we've seen a little bit wider spreads between Conway and Belvieu, and that's why you're seeing an uptick in optimization. On the marketing, the big thing we've seen in the second quarter had been we were moving a lot of propane from the Bakken and from the Northeast into Conway and that shows up in our marketing our - that's where our truck and rail activity is housed, we're seeing a lot of movement come into the Mid-Continent. Over December period time, it will be the second, third quarter, we will see that moving of propane.

Thank you.

Our next question will come from Theresa [Indiscernible] with Simmons and Company.

Hi, good morning, just a quick follow-up on the NGL supplier opportunities in the SCOOP and STACK. When you're talking about the 100,000 incremental barrels per day of NGL, can you just give us a sense of what kind of pricing assumptions are baked into this and whether strategic [Indiscernible] like sub 40?

Pricing - I'm sorry, pricing assumptions for the NGLs, what we were charged, only thing we have put out there is that the average price we have in the Mid-Continent is roughly around $0.08 per gallon. That is a combination of both when we delivered Conway into Bellevue, most of these will probably go to Bellevue, so you're probably $0.08-plus per gallon of what we are charged for this movement if our customers want to go to Bellevue.

Okay, great. And just one other one on the continued strength in process in fractionated volumes. Should we expect this to continue into Q3 or just expect more of like the seasonal shift in Q4 as usual? And also would you think of adding even more incremental processing plans aside from the three connections expected in the second half of ‘16 if we continue to see this increase in volume?

When you look at the fractionation volumes in the uptick you see from the first and the second quarter, you've got to be a little careful, because we did have a lot of raw feed in storage from the first and the second quarter. So, you really need to kind of think about those averages across the two and we had a little bit spot volume and some more ethane recovery that kind of boosted those numbers up there. We still think that we look at our guidance that we have out there for fractionation will be middle, will be right around the middle, maybe a little better than that for the rest of the year.

Okay, great. That’s it from me. Thanks a lot. I appreciate it.

And our final question will come from Tom Abrams with Morgan Stanley.

Yeah. Just a question on the Bakken and kind of how does it work question, as the wells produce and you get more gas I think as they mature, do you get more NGLs such that if production were to say, oil production were to say remained flat that you would actually see an increase in gas processed and an increase in NGLs recovered.

Kevin, you’re following?

Yeah, I mean we have especially in the Williston we have seen an increased gas to oil ratio in the core, so that's where we have seen as oil has been flat to slightly declining, the gas produced out of the basin has actually strengthened over the last several months. It came off a little bit in May - in April and May, but that's the phenomenon. More of it I think is related to the wells being drilled in the core as much as it is just the increasing gas as the oil declines.

I got you.

The only thing I'd add to that is in the core that those gas to oil ratios are much higher than in other parts of the basin, right.

That’s correct.

Yeah.

Good. Thanks a lot.

That concludes today’s question-and-answer session. I'll turn the conference back to Mr. T.D. Eureste at this time for any additional or closing remarks.

Thank you. A quiet period for the third quarter starts when we close our books in early October and extends until earnings are released after the market closes in early November. Thank you for joining us.

This concludes today’s call. Thank you for your participation. You may now disconnect.