Andrew Ziola - Vice President, Investor Relations Terry Spencer - President and Chief Executive Officer Walt Hulse - Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs Kevin Burdick - Executive Vice President and Chief Operating Officer Sheridan Swords - Senior Vice President, Natural Gas Liquids

Eric Genco - Citi Danilo Juvane - BMO Capital Markets Michael Blum - Wells Fargo Christine Cho - Barclays Craig Shere - Tuohy Brothers Chris Sighinolfi - Jefferies Ethan Bellamy - Baird

Good day, everyone and welcome to the Second Quarter 2017 ONEOK Earnings Call. Today’s call is being recorded. And at this time I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you, Vicky and good morning everyone and welcome to ONEOK’s second quarter earnings conference call. A reminder that statements made during this call that might include ONEOK’s expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision 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 this morning is Terry Spencer, President and CEO of ONEOK. Terry?

Thanks, Andrew. Good morning and thank you all for joining us today. I would like to start by welcoming Andrew back to the team and I also want to acknowledge T.D. Eureste for his many contributions to our Investor Relations efforts during some of the most challenging times over the last few years. T.D. is now Vice President of our Treasury team. Joining me today on this call is Walt Hulse, Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs and Kevin Burdick, Executive Vice President and Chief Operating Officer. Our second quarter ended with the completion of the ONEOK and ONEOK Partners merger transaction, which included the acquisition of all of the common units of ONEOK Partners we did not previously own. ONEOK is even better positioned to execute our long-term growth strategy for the benefit of both our legacy and new ONEOK shareholders. We have many opportunities for organic growth across our businesses through our diversified and integrated midstream asset footprint in some of the nation's most active shale plays. We can provide our current and new customers with full service midstream capabilities. As I have said before, growth opportunities continued to develop in the areas we operate. Our second quarter 2017 financial results were solid with volume growth in both our gathering and processing and natural gas liquids segments. Higher average fee rates in our G&P segment and higher transportation revenues from completed expansions in our natural gas pipelines segment. Walt will review our financial results and provide additional color on our 2017 guidance, which was updated to reflect the merger transaction and our business outlook for the rest of 2017. Kevin will discuss our operational results in more detail as well. With that, I will now turn the call over to Walt.

Thank you, Terry. ONEOK reported strong financial results for the quarter, including healthy dividend coverage of approximately 1.5 times for both the second quarter and through the first half of 2017. As noted in our earnings release, second quarter results included approximately $43 million in one-time and transaction related charges, which impacted second quarter earnings per share by $0.12 per share and dividend coverage by 0.18 times. Last week, we increased our quarterly dividend by 21% to $0.745 cents or $2.98 per share on an annualized basis. The successful completion of the ONEOK and ONEOK Partners merger transaction combined with the proactive steps we have taken to improve our leverage position and balance sheet are being recognized. In July, ONEOK received credit rating upgrades to investment grade from both S&P and Moody’s. Both agencies also have established stable outlooks on the company. ONEOK’s trailing 12-month GAAP net debt to EBIT was 5x at June 30, including transaction costs, 4.9 times without the transaction costs. We continue to expect to reduce leverage to a target of 4x or less by late 2018 or early 2019 primarily driven by expected growth of adjusted EBITDA. In July, we took additional proactive steps to manage our future debt maturities and liquidity by utilizing ONEOK’s cash on hand to immediately reduce commercial paper borrowings, completing a $1.2 billion senior notes offering redeeming all $87 million of our 6.5% senior notes due 2028 and repaying $500 million of our $1 billion term loan due 2019. As a result, we now have nearly $2.2 billion of available capacity on our $2.5 billion credit facility. 2017 guidance has been updated to reflect the June 30 close of the merger transaction with the only adjustment to the midpoint of adjusted EBITDA being the impact of transaction expenses. Our original guidance provided on February 1 did not include the one-time or transaction-related charges I mentioned earlier and the original guidance also assumed a January 1 transaction closing day. We narrowed ONEOK’s adjusted EBITDA guidance to a range of $1.89 billion to $2.06 billion and increase our growth capital expenditure range by approximately $70 million to reflect recently announced projects. Please refer to our news release, investor presentation and the 10-Q filings for additional details on the quarter. I’ll now turn the call over to Kevin for a closer look at each of our business segments.

Thanks, Walt. Starting with our natural gas liquids segment, NGL volumes gathered averaged approximately 807,000 barrels per day, a 6% increase compared with the first quarter of 2017 and NGLs fractionated increased 8% compared with the first quarter. Bakken NGL pipeline volumes were up 8% averaging 141,000 barrels per day in the second quarter. NGL volumes gathered from the STACK and SCOOP areas of the Mid-Continent and out of the Permian basin also increased during the second quarter. Mid-Continent volumes increased 4% and volumes on our West Texas LPG pipeline increased 7% compared with the first quarter 2017. The Permian basin remains one of the most active basins in the country and we continue to have promising discussions with producers and processors in both the Midland and Delaware basins to expand our West Texas LPG system to capture expected production growth. We connected two additional third-party natural gas processing plants during the quarter both in the Mid-Continent in addition to the three plants connected in the first quarter of 2017. And we have already connected one additional third-party plant in the Permian basin in the third quarter. The total combined NGL production of these 6 new plants is expected to run to approximately 30,000 barrels per day by the end of 2017 and increased to more than 40,000 barrels per day in 2018. Ethane rejection levels on our NGL system remained relatively unchanged in the second quarter 2017 averaging more than 150,000 barrels per day similar to first quarter levels. We continue to expect an increase in ethane recovery on our system through the remainder of the year as new petrochemical plants are completed. For the natural gas gathering and processing segment, second quarter 2017 adjusted EBITDA increased 23% compared with the first quarter 2017 primarily driven by volume growth in the Williston basin and STACK and SCOOP areas. The segment’s average fee rate was $0.87 per MMBtu in the second quarter 2017 compared with $0.76 per MMBtu in the second quarter of 2016, a 14% increase which was driven by increased volumes on higher fee contracts in the Williston basin. We expect the segment’s average fee rate to be closer to $0.85 for all of 2017 as our volume mix shifts across regions and contracts depending on producer activity. We achieved our highest level of volumes processed in the Williston Basin during the second quarter, with volumes averaging more than 820 million cubic feet day, a 13% increase compared with the first quarter of 2017. Mid-Continent volumes average more than 690 million cubic feet per day, a 4% increase during the quarter. Despite commodity price fluctuations during the quarter, drilling rigs have remained steady. We currently have more than 30 rigs operating on our dedicated acreage in the Williston basin in approximately 15 rigs on our dedicated acreage in the STACK and SCOOP areas. In the Williston Basin, we connected 108 wells during the second quarter. We expect to connect 400 wells in the basin this year and estimate there are still approximately 300 drilled, but uncompleted wells on our dedicated acreage. With this new production that has recently come online, our available processing capacity is now approximately 150 million cubic feet per day in the Williston Basin. Growth in the Mid-Continent continues to be driven by increased activity and strong production results from our customers in the STACK and SCOOP. Recent activity levels and production results continued to exceed expectations. We connected 27 wells in the Mid-Continent during the second quarter and we expect to connect approximately 100 wells on our dedicated acreage in the Mid-Continent in 2017 as our volume ramp is expected to be weighted more towards the second half of the year. In the natural gas pipelines segment, second quarter 2017 adjusted EBITDA increased 18% compared with the same period in 2016. The segment continues to benefit from higher fee based earnings driven by increased firm contracted capacity in connection with the expansions of our West Texas transmission pipeline and our Permian Basin joint venture Road Runner pipeline, which will both completed in October 2016. In our earnings release, we provided updated segment specific guidance and volume expectations. Overall, we have increased adjusted EBITDA for our natural gas gathering and processing and natural gas pipelines segments and increased our G&P volume outlook. These increases were primarily driven by higher than projected volumes in the Williston Basin and STACK and SCOOP areas and our expectation that drilling and completion activity will remain strong through the second half of the year based on recent discussions with our producer customers. We narrowed our adjusted EBITDA guidance in the natural gas liquids segment reflecting adjustments for the timing of the expected volume increases from recently connected third-party plants. In mid-June, we announced NGL and natural gas related expansion projects totaling approximately $170 million to accommodate growth in the STACK area. Projects include a 60,000 barrel per day expansion of our Sterling III NGL pipeline, increasing its capacity to 250,000 barrels per day and additional NGL gathering system expansions in the area, which are all backed by a long-term contract and plant dedications. These expansions are expected to be complete by the end of 2018. Additionally, we announced the construction of a 30 mile natural gas pipeline through the heart of the STACK to connect with an existing third-party natural gas processing plant in Oklahoma, which will provide us access to an additional 200 million cubic feet per day of capacity and is expected to be in service by the end of 2017. And most recently on Monday, we announced plans to expand our Canadian Valley natural gas processing facility in the STACK area of Western Oklahoma. The project will increase capacity at the facility to 400 million cubic feet per day from 200 million cubic feet per day and is expected to be complete by the end of 2018. It also will provide approximately 20,000 barrels per day of additional volume into our NGL gathering system. Combined with the third-party processing agreement I just mentioned, this plant will bring our total Oklahoma processing capacity to 1.1 billion cubic feet per day. The additional capacity is needed to support the rapidly growing production in the area and is backed by more than 200,000 acres of dedication primarily fee-based contracts and minimum volume commitments. Terry, that concludes my remarks.

Thanks Kevin. A couple final comments as it relates to our future growth projects before we take your questions. We continue to grow our backlog of potential capital growth projects that we are working hard to develop and earn customer commitments. Once we do so we will certainly announce those projects. Additionally I am confident that over time, we will add to our backlog as we have done in the past. We expect to continue to grow in our existing businesses and continue to focus on applying our core capabilities to create value for our customers and investors. Finally, I want to thank our employees for their continued hard work, dedication and commitment and operating our systems safely, reliably and environmentally, responsibly every day. Operator, we are now ready for your questions.

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

Hi, good morning, guys.

Good morning, Shneur.

Just two questions here, the first one is with respect to guidance, I was wondering if you can square something for me, I recognized that you have raised guidance at the operational level, because of Bakken volumes, however when I look at the kind of the midpoint it doesn’t suggest a surge in volumes, but at the same time I look at your performance, I look at comments from E&P producers, it seems like the – your volume guidance should have been a little bit higher in the – in the Bakken, is there a hint of conservatism or is there a bottleneck that we should be thinking about. And then staying on the guidance question, the NGL segment revision sounds like it’s a delay in some [indiscernible] by producer, is that just shifting earnings into next year, I was just wondering if you can give a little bit of color about that as well?

Yes. Shneur, this is Kevin, I will take the G&P question first. No, I don’t know that we believe there is conservatism built into our volume guidance for that we provided. One thing when we think about the Williston, to me look you do the math, we are showing that we are going to need to grow in Q3 and Q4 to meet the midpoint of the processed volume guidance. The other dynamic going on there especially what the Williston is winter. So we have to – we learned from January, last January and February that we do have a little bit of winter weather factor built into that guidance as well. As we look from an NGL repeat – could you repeat the question on NGL side again.

On the NGL I was wondering if you can give just a little more color as to why the revisions there is it something that rolls into ‘18 or how should we think about that?

Yes. The downward revision, small revision to our volumes in the EBITDA on the NGL segment was related to timing. We clearly, don’t see that as a change in our point of view on the activity levels. It literally was just as that the specific timing the plants came online and how the volumes then are ramping. So yes, it would be, we don’t necessarily see our exit rates changing, it was more a factor of when they came online and how that played into the full year average.

Okay. And then a final bigger picture question, when I sort of look at Oneok’s earnings performance and CapEx spend over the last 2 years, relative to your peers your capital investment intensity has been fairly low, I do recognize that you haven’t announced capital investments, but relatively speaking versus earnings growth which has been much higher than your CapEx expense, are there more opportunities to continue growing your business while keeping your capital intensity on the lower side. I suspect you have done some off-take agreements and asset optimizations, but is that largely done and future growth will kind of have a corresponding one-for-one investment in CapEx or are there more opportunities continue growing earnings without the same intensity on CapEx that we see in some peers?

Shneur, I will – let me make a couple of comments and then if the Kevin has got some of that he can follow-up. We do have some more opportunity in terms of – in terms of taking advantage of the headroom that we have in our businesses. That will kind of come and go and we will kind of work those opportunities dependent upon what’s out there in terms of the G&P landscape. So that will be a bit of a moving target, but we think there is more opportunity to do that. But I think just fundamentally speaking we are going to see more capital spend going forward than we have seen from our traditional run rates over the last couple of years, just based upon the fundamentals that we are seeing the strong rig counts that we are seeing right underneath our noses. So I do expect that run rate to increase as we continue to develop those projects and those projects that hit the full menu of services that we provide NGLs, G&P, fractionation and what have you, so as those come together and materialize, we will adjust our backlog of unannounced growth projects appropriately and certainly we will provide you more color as we move forward. Okay, Kevin anything that you would add there.

Great. Thank you very much guys. I appreciate the color.

Thank you.

We’ll go to Eric Genco with Citi.

Hi, good morning. I guess this is going to touch on the last question a bit, but in terms of the extension with Canadian Valley, you are getting 200 a day for 145 million to 155 million. I am just thinking back to the – before the commodity price collapse of 2015, you had plans for the Knox plant 200 a day again for 365 to 470 million. So, from a cost per capacity standpoint, this is clearly better. My question is why not choose to expand Canadian Valley in the first place over Knox a few years ago? And then is there something that’s changed perhaps in location of where Knox is going to go that makes it less necessary or is there potential to revive that plant. How should we think about all that?

Hi, Eric. This is Kevin. Yes, three is a variety of things I think that are going on with that Delta. Sorry we had some weird feedback here. First I would say yes when we announced Knox it was a completely different business environment at that point. I mean it was the heyday of the growth and so that drove costs for materials and services were higher. The second thing is the rationale for the Knox location was at that point in time the SCOOP was really the hot play and that’s where the majority of the activity was and Knox is geographically right in the heart of the SCOOP. And then – so as the drilling activity shifted a little bit to the north and the STACK became really a prolific play, we started taking a look and that’s where our volumes were going to show up and therefore being able to leverage the facility – existing facilities at the Canadian Valley site became the appropriate place to put that next tranche of capacity we are bringing online. That also had an indirect effect of the gas coming on in the STACK where we had a significant amount of infrastructure already in place, so that also drove down the field infrastructure necessary for the plant as well. So, a combination of all those factors we still have is the stack matures, we still have the ability we could put another train at that same facility. If the SCOOP continues to evolve that wouldn’t preclude us from putting another plant down at the Knox site that we have referred to previously.

Okay that’s very helpful. And then just real quick on the NGL segment showed an 11% increase sequentially in operating costs versus 6% in volumes and you talked about your ability last quarter to run the Bakken NGL line above nameplate in this quarter EAA did. Did that cost you on the operating expense front or is there something else going on there and what is the status of the pipeline expansion there? As 3Q ‘18 is still a good target you come earlier would be good if it did 20 years Dawson capacity there and then possible expansions beyond the 160?

Yes. I will start from a cost standpoint, no, there was no relationship between the cost increase and in the capacity on the pipeline that was purely we had timing impact of some maintenance and expense projects that occurred in the second quarter. As we think about the Bakken capacity, we still have some headroom. We have said it will run nameplate. Clearly, we are having conversations with a variety of our customers both in the not just in the Bakken, but also the powder and that in the DJ about additional capacity. So, we were working through what that expansion might look like the timing of such.

Okay. We will now take our next question from Danilo Juvane with BMO Capital Markets. Please go ahead.

Thanks and good morning everyone. In the G&P segment, NGL sales volumes average 186,000 barrels per day. I recall on the last quarter’s call we talked about the delta year-over-year being driven by ethane recoveries. And since we are talking about ethane recoveries being essentially flat between the first and second quarters, I wanted to make sure that, that increase is just driven by propane plus?

Yes that volume was entirely driven by propane plus.

Got it. And second question for me, I didn’t see anything in the release, so I apologize if I missed it, but typically you disclosed your equity NGL data and customarily also report hedges that, that you often update. Did you firstly update the hedges and is there any equity NGL data available?

That will be part our two that we will file here today, so yes we didn’t put it in the earnings release, but it will be in the 10-Q.

Thank you. That’s it for me.

We’ll go to Michael Blum with Wells Fargo.

Hi, good morning everyone. I am wondering can you give us an update on where things stand on the West Texas LPG line and the case there? Thanks.

This is Kevin. Yes, on West Texas, we are still in the process. From the rate case standpoint, the ALJ has the information and we are awaiting on that and we continue to expect we will have resolution on that by the end of the year and are confident in our case.

Okay. And then little bit of a nitpicky question, but just wonder if you can provide a little background on, there is a footnote in these release related to contribution to the ONEOK foundation of 20,000 shares that had a value $20 million, which looks like was part of the adjusted EBITDA calculation. Can you just kind of talk about what’s going on there?

Yes, sure. Michael, this is Walt. The ONEOK Foundation was a foundation that we created in 1997 to support the communities that we operate in. Over the course of the last several years, we haven’t made any contributions to that given the business environment and with the closing of the transaction, we saw it as an opportune time to true up that foundation and made a contribution of $20 million in the form of a preferred stock.

Okay. So, on a go forward historically I guess before the last 3 years, you would be systematically contributing and that would be running through the statements?

That’s correct. And it was periodic. It was not necessarily annual event just from time-to-time.

Okay, alright. Thank you very much.

We’ll go to Christine Cho with Barclays.

Hi, everyone. I actually wanted to start on West Texas. One of your customers there announced plans to build their own NGL pipeline, which would imply that they are pulling volumes off your system once that comes online. Would you be able to give us an idea of how much you are expecting to come off and how we should think about the outlook for the pipeline and whether or not we should think that the expansion that you guys have previously talked about gets pushed out?

Christine, this is Sheridan. Look, I can’t take specifically how much any shipper on the pipeline moves, but what I can tell you is no shipper on our system moves more than 25% of the volume on that. So, everybody is below 25%. And if we would lose volume then we do know that pipeline coming in. We are highly confident that we will be able to re-contract that volume at definitely better rates than we are getting today, because we are getting the lower rates and also that would give us the opportunity to offer bundled services to also get practices in there. And actually we are working very diligently and close to have an expansion on the West Texas pipeline back by customers and we don’t see this new pipeline having any impact at all on the timing of that expansion?

Sheridan, you might clarify, when you said you can’t provide that information you might clarify, why that’s the case?

The West Texas pipeline is a regulated pipeline and we can’t – as an operator of that pipeline divulge shipper – specific shipper information. We can only give generalities about what it is. That’s why I say nobody is greater than 25%. I can’t tell you specifically what that one customer has.

Okay, that’s helpful. Thank you. And then on the Canadian Valley expansion is that being driven by new acreage dedications or faster than expected ramp on production for from existing acreage dedications? Also, if you could talk about the ability to add more trains at this facility if there is need? And lastly how should we think about the need or potential for Arbuckle Sterling expansion beyond Sterling III with these additional volumes?

Hey, Christine, it’s Kevin. Yes, when we look at the STACK in general, obviously the production growth we have seen and you just back up away from our specific G&P presence and you look at what the producers are doing in the region, it’s been pretty staggering with some of the results they have reported here over the last several months. So, most of the – the vast majority of the capacity needed is going to be to serve existing acreage dedications that we have and under long-term contracts. We have added a few small additional contracts here and there. But the primary expansion and the capacity is needed to serve those existing just more growth on those existing contracts. And yes we do as I mentioned earlier we have the ability to put at least one more train and potentially two at the Canadian Valley facility as the STACK continues to grow. And again when you are looking it over hundred rigs in the STACK and SCOOP combined, clearly as we are talking and in Sheridan’s business and the NGL side talking to a variety of processors and producers an expansion of our – additional expansions needed to our book or are not out of the question.

Okay, great. And then just going off the STACK/SCOOP, several weeks prior to the announcement of the expansion on Canadian Valley you guys announced that you would be offloading 200 million cubic feet a day processing from that region to a third-party plants, could you explain why these volumes aren’t being directed to the Canadian Valley plant, is it more of a timing thing, a geographical thing or anb economic decision?

Is was really all the above, we haven’t – we just had an attractive opportunity presented and we work with our counterparty and the combination of timing and we were able to get this capacity in place sooner than we would have built. We would have been able to build an existing train and obviously economics factored in. We wouldn’t have done it if it wasn’t attractive to us and our customers.

Okay, great. Thank you.

And Craig Shere with Tuohy Brothers is next.

Good morning.

Good morning Craig.

It looks like on Slide 4 of the deck that NGLs volume were up sequentially, pretty well and that was also highlighted in the prepared remarks, but on Slide 7 there is some commentary about consequential operating performance, down $9.9 million forward margin on seasonal product demand, is this more a product mix issue, is this something we should see annually does it have anything to do with the adjustments to volumes for the year unexpected third-party interconnects?

No Craig, this is Kevin. No, it’s nothing we – yes, it is seasonal. So from the standpoint of what we expect and in fact when we – if you look at last year as we were explaining our second quarter, we had similar seasonal impacts. This is volume shipped on our north system that are seasonal in nature and so that’s what’s driving that aspect. The other – the cost side is what I referenced earlier it was just a timing. Typically as we come out of winner, we end up having a higher level of maintenance and expense project activity and that’s what drove that increase sequential quarter-to-quarter from a cost perspective.

But if the overall volumes on your system higher sequentially, it is a simply product mix can you explain that a little more?

Yes. The volumes that we are talking about, the volume growth isn’t necessarily on the distribution system. Some of the earnings is shown up in the exchange services side of the business. So the volume specifically in the margin on the transportation side is related to that seasonal North system.

Okay. And then a follow-up on Shneur’s question about unannounced growth projects, I think you all have already announced with two press releases about $300 million in aggregate growth CapEx, an opportunity set that was previously described that $1.5 billion to $2.5 billion as you think about our book goal and this expansion maybe over the Overland past JV needing some expanded capacity over time that additional GMP capacity requirements, do you see this $1.5 billion to $2.5 billion opportunities set reduced by about $300 million, do you see some additions on the ground expanding, contracting from that initial outlook?

Craig, now we don’t see it reducing. We see it go in the other direction just given the fundamentals that we are seeing under our footprint today.

And in terms of the timing for Terry, we didn’t have huge dollar amounts relative to your historic spend announced, I mean we did have a couple of nice announcements, could you see more material announcements in the second half here?

We could see that, certainly in the second half we could see it in the early 2018.

Great, I appreciate the help.

You bet.

Next is Chris Sighinolfi with Jefferies.

Hey Terry, good morning.

Hi good morning Chris.

Just want to – we are at the point in the call, a lot of the big new have been hit, so I wanted to hit on some of the maybe some of it set additional items, but on the optimization and marketing commentary and I know I have inquired with Sharon about this in the past, but it looks like if I were to follow sort of the Opus prices or the Bentek [ph] reported prices that regional spreads on prices and intra-product price perhaps present an opportunity for greater optimization in marketing year-on-year, do you highlighted in the release that there was actually a headwind, so I am just I know it’s a complicated series of decisions around the optimization in marketing activities and so I didn’t know if there was a simplistic way to plan maybe what happened in the market year-over-year net to what we are seeing on the quoted prices?

Chris really this is Sheridan, year-on-year most of that or all of that delta that’s down decrease was due to our marketing activity. And really it was due to timing on our inventory that we have sold out in fourth quarter, third and fourth quarter that we have seen prices drop in the second quarter that we will realize that back in the fourth quarter, third and fourth quarter when those sales come on. So it’s all in marketing it was not in optimization.

Okay. And that’s something just to clarify what you just said, is that something you saw last year in the fourth quarter are you saying, we would expect to see it in the back half of this year some of these gains in the back….?

Actually last year we had the opposite effect, where we had inventory and prices rose last year and that’s in the second quarter. So we kind of got a little bit of two different things going on with our inventory, but the cells are out there in the fourth – third and fourth quarter work what will realize higher third and fourth quarter on the marketing for the decrease in the second quarter.

Got it, okay, perfect. And then I guess following-up on the change in the gathered volumes for NGL gathered volumes versus a static forecast on what you were expecting or what you are still expecting on the frac side, just looking at that if I think about $25 million of segment EBITDA decline on 25,000 barrels a day of full year movement on the guidance [Technical Difficulty] by somewhere around $0.065 a gallon, I know when you quote the regional areas some include frac, some don’t and it would seem like that’s more aligned with an area that includes fractionation services that’s if an absent, so I am just wondering were you – was that gathering amount planned to be frac then you were just sort of previously at the high end of where you thought the frac items would be and backgrounds with metal or how do we interpret I guess the financial implications of the volume if you could help us with that would be helpful?

Whether the volumes got spread out over the whole system, but I would say most of that we were planning on cracking.

Okay, perfect. I guess one follow-up question Michael Blum asked earlier with regard to the preferred equity placement that the contribution, is there an associated – it looks like there is an associated preferred distribution on that at least recorded small very small quarter, just wanted if you give us a sense what the run rate on that might be?

Sure it’s a 5.5% preferred on the $20 million. So it’s reasonably immaterial in the overall scheme of things.

Okay. So just relatable well that comes out every quarter, it’s not an audit – it’s not twice a year, every quarter?

It’s quarterly, yes.

Okay. And then I guess final question for me, we have seen a very nice up-tick, continued up-tick in the average be on your GMP activities, I am guessing based on your earlier commentary that that might I think talking about that maybe sliding back down a little bit given a composition of volumes, I am assuming since it continued to rise that the surprise, upside surprise on Williston Basin activity, I am just wondering how you think about that progressing now given what the activity has been, I think you have said $0.85 for the full year, I guess any help in how you are thinking about producer activity across the [indiscernible] has been moved into 2018 would be really helpful?

Yes. Chris, this is Kevin. We clearly see growth in both our regions in the Williston and in the Mid-Continent of STACK and SCOOP primarily. As we move forward, so yes the fee rate will move around just literally quarter-to-quarter as that volume mix changes between a little bit higher fee rates in the Williston versus the Mid-Continent, so as the volume growth kind of shifts from one to the other that that fee rate will move around. We still feel good about $0.85-ish through the rest of this year or for the full year. How that moves around will just depend literally on the timing of individual well completions and how the volumes grow sequential quarter-to-quarter.

So Kevin, it’s fair to say that you should – we are probably not going to see any step function changes in that weighted average fee rate?

No, part of the reason for the pretty significant step up from Q1 to Q2 was because we had the severe weather impact to the Williston volumes in Q1, so that as those volumes grew substantially relatively – comparatively that’s what drove up the fee rate. But going forward no, we shouldn’t see step change functions in that fee rate.

Okay. So does the tone we are in right now is a pretty comfortable [indiscernible] found around sort of high to low pace on competition quarter-to-quarter, is that a fair understanding?

Yes.

Okay. Thanks a lot guys. I really appreciate the time this morning.

Thanks Chris.

We will go to Ethan Bellamy with Baird. Please go ahead.

Hi guys. Good morning. Hey, you have just – you guys have done a really great job in the past few years of a multi-year strategic shift in financial structure and with the [indiscernible] on you now have a really good cost of capital what’s next, what’s the next corporate strategy goal, is it more aggressive on M&A, I mean where do you go?

Well, Ethan as far as aggressiveness on them M&A nothing has really changed in terms of our view. From an M&A perspective we are always interested in strategic opportunities, certainly the challenge associated with those as actionability as you are well aware. But our strategy remains heavily organically focused and certainly where are we building off this big asset footprint that we have, the incremental returns or the incremental investments that we are making and the returns that we are seeing are very attractive. And we will stay focused on taking care of our customer needs, building off of this existing footprint. And then from time-to-time, acquisition opportunities if they present themselves and they fit with this with this NGL centric kind of strategy that we have certainly we will pursue those. But that’s kind of help things…

So the sea change in your cost of capital really haven’t changed your strategy or the way you are thinking about growing things…?

It really hasn’t, I mean we are certainly from a business perspective and as we think about our growth strategies, they are still spot on with where we have been in the past. I will tell you that we are all – we have always been in a prospecting mode in terms of M&A regardless of our structure. And we are still there, but they got to certainly make sense, got to make a lot of sense for us.

Okay. And then one really granular question, how much behind pipe gas in the block and is still low hanging fruit in terms of capturing things are being flared right now?

When you say behind pipe, are you talking about it from a geologic perspective?

Yes. I am?

Okay. So Three Forks, are you comfort Kevin….

Well, I heard a couple of question. You just want to get at how much low hanging fruit from a flaring perspective?

Yes. Well, I am just thinking about maybe also something that’s getting flared now, but you know that there is going to be some wells drilled. You don’t have pipe in the area now that kind of I am just trying to get a sense for the opportunity there, because I know a lot of your volume catch-up has been intrinsic, going out and capturing that that for a gas?

Now, we have – in large part we have captured a good chunk of that low hanging fruit. I mean we still estimate we may have 60 million to 70 million cubic feet a day flaring behind our system. But again that’s as our volumes have grown we have lowered, at the same time we have lowered that flared gas. So there is always going to be some level of flaring. We might estimate 30 million to 40 million a day that’s just going to be ongoing. So there may be another 20 million that we are continuing to pursue that you would kind of call low hanging fruit. But for the most part our operations team has done a fantastic job and relative to the rest of the basin our flaring is well below the statewide averages.

And is the state left in your face about this now?

Well, yes from the standpoint of the industry in total is delivered and specifically yes. So yes, from the standpoint that industry stepped up and has met the flaring targets and is – and it takes it extremely seriously. And as we worked with our customers to drive the flaring down, yes it is it is limited and eased the pressure.

Good to hear. Thanks gentlemen.

Great. Thanks Ethan.

And that will conclude our question-and-answer session. I would like to turn it back to Andrew Ziola for any additional or closing remarks.

Okay. Well, thank you all very much for joining us. Our quite period for the third quarter starts when we close our books in early October and extend till our earnings are released after the market closes in early November. Again, thank you for joining us and feel free to follow-up with me in the coming days. Have a good rest of your day.

Thank you very much. And that does conclude our conference for today. I would thank everyone for your participation.