Ladies and gentlemen please standby. Good day and welcome to the ONEOK and ONEOK Partners Fourth Quarter 2016 Earnings Call. Today's conference is being recorded. At this time I'd like to turn the conference over to today's host Mr. T.D. Eureste. Please go ahead sir.

Thank you and welcome to ONEOK and ONEOK Partners fourth quarter and year end 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 all 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 our Senior Vice Presidents; Wes Christensen, Operations; Sheridan Swords, Natural gas liquids; and Phil May, Natural Gas Pipelines. We also have Kevin Burdick, who is recently promoted to Executive Vice President and Chief Commercial Officer reporting to me with responsibility for all of our business segment commercial activities. Kevin has served a number of key leadership roles and performed at a high level. I have no doubt that Kevin's exceptional leadership skills and experience will continue to serve the company well in his new role. Congratulations to Kevin. Thank you for joining us this morning to review our 2016 and fourth quarter results. ONEOK and ONEOK Partners reported strong 2016 financial performance as ONEOK Partners adjusted EBITDA increased nearly 18% compared with 2015. Increased fee based earnings drove double-digit adjusted EBITDA growth in all three of our business segments. This strong year-over-year adjusted EBITDA growth was achieved despite increased ethane rejection and severe weather in December that impacted volumes in our natural gas liquids and natural gas gathering and processing segments in both the Williston Basin and the Mid-Continent. The impact of the severe weather and increased ethane rejection in December reduced fourth quarter results by approximately $15 million. Severe weather continued early in the first quarter of 2017 impacting volumes but volumes have rebounded significantly in February to November 2016 levels which were some of our highest monthly volumes. We expect year-over-year adjusted EBITDA growth in 2017 to be weighted towards the back half of the year,…

Thanks Terry, starting with the partnership fourth quarter and full year 2016 adjusted EBITDA increased compared with 2015 by approximately $20 million and $275 million respectively. ONEOK Partners distribution coverage ratio was 1.03 times for the fourth quarter and 1.09 times for the full year of 2016, a substantial improvement compared with the 0.86 times coverage for the full year 2015. The slightly lower fourth quarter distribution coverage ratio as anticipated was due to the timing of maintenance capital spending. Credit metrics again improved the partnerships already strong balance sheet with a trailing 12 months GAAP debt-to-EBITDA ratio of 4.2 times at December 31st. ONEOK maintained its healthy dividend coverage throughout 2016 ending the full year coverage of 1.31 times or approximately $250 million of cash on hand and an undrawn $300 million credit facility. We expect to utilize ONEOKs available cash to pay down consolidated debt this year. ONEOKs 2017 financial guidance was issued as if our proposed merger transaction with ONEOK Partners closed on January 1. We expect to true up the guidance for net income, income tax as a non-controlling interest once the timing and related impacts of the transaction are known. We still expect closing to occur in the second quarter. Adjusted EBITDA and distributable cash flow should not be materially impacted by the timing of the transaction closing. For the NGL segments 2017 adjusted EBITDA guidance we are mindful of the primary components that may impact results including the timing and amount of additional ethane recovery and incremental volumes from the STACK and SCOOP. Based upon our current assessment of producer activity in petrochemical and construction we expect to be within the guidance range as this segment delivered nearly $1.1 billion in adjusted EBITDA in 2016. We expect to lower cost of funding resulting from our strong financial performance -– our strong financial performance and successful efforts to reduce commodity price risk combined with the recent transaction announcement which eliminates incentive distribution rights. Also the credit rating agencies have viewed ONEOK favorably placing ONEOK on review for upgrade to investment grade following the closing of the transaction. The expected growth in adjusted EBITDA and use of the excess cash on hand to repay debt should enhance ONEOK -- should enable ONEOK to improve its credit metrics reducing consolidated debt to EBITDA to round our target of four times in the next 18 to 24 months. In terms of timing and next steps for the merger transaction we expect to file a registration statement and joint property statement within the next week or so. Once the registration statement is declared effective by the SEC, we will mail the joint proxy statement to our shareholders and unit holders and set unit holder and shareholder meetings to be held on the same day. As of now our best estimate is for the transaction to close in June. I'll now hand the call back to Terry.

Thank you, Derek. Let's take a closer look at each of our business segments. Starting with our natural gas liquid segment, 2016 adjusted EBITDA for the segment increased more than 10% compared with 2015 benefiting from new natural gas processing plant connections in the Williston Basin and STACK and SCOOP areas and increased ethane recovery during the first half of the year. Severe winter weather continued to impact our system in January however NGL gathered volumes have rebounded in February averaging approximately 780,000 barrels per day this month. This average is more in line with our November 2016 volumes. We've also seen higher NGL product price differential and location differentials which we expect will partially offset early year impacts from weather. We expect 2017 NGL volumes to be driven by increased drilling activity across our system and the ramp up and full year benefit of the six natural gas processing plants we connected in 2016. We also expect to connect an additional six plants this year including one in the Rocky Mountain region, three in the Mid-Continent, and two in the Permian Basin. These new connections will increase the partnerships total third party plant connections to nearly 200. Producers are planning to move more rigs to the STACK and SCOOP area and the Williston Basin by mid-year and with the ramp up of new processing plants we expect volumes to increase significantly during the back half of 2017. With respect to ethane we continue to expect ethane recovery levels to fluctuate throughout 2017 but we are also seeing positive signs from petrochemical and export facilities so far this year. At least three world scale petrochemical facilities are slated to begin operations in the second half of 2017 in addition to increased capacity utilization at new export facilities. Additionally a new…

Thank you. [Operator Instructions]. And we'll take our first question with John Edwards with Credit Suisse.

Good morning everybody and you know thanks for updating us on what the narrative, just as a follow up Terry could you just walk us through the fourth quarter Permian gather volumes a bit below average for the year and I was just thinking it wasn't -- that wasn't going to be in a weather impact there, so any color of what happened there and then how you think that'll turn up in 2017, you are a little bit beyond the detail you provided in the narrative already?

Sure John I am going to let Sheridan kind of walk you through those components.

The first thing John we did see a little bit of impact of weather in the Permian but West Texas pipeline which a lot of people think of as just a Permian did see more weather impact through the Barnett Shale and we did see some methane more increased ethane rejection out of -- on the West Texas pipeline in the fourth quarter. And we should continue to see growth in the Permian. As we go in, the Permian has been fairly steady through the year but we are connecting additional plants in the Permian, two additional plants this year will increase our volumes out of the Permian.

Okay, that's helpful and then just as far as ramping up to the overall guidance of 800 to 900 that you provided a few weeks back, I think you indicated in your opening comments you're already seeing in February something like 780, so would it be fair to say that you're thinking you'll cross over, I mean when would you expect to across north of 800 and then would it be fair to say because it's the second half situation that you're going to be closer to the 900 range kind of in the third and fourth quarters, is that the right way to think about it?

I think to think about it definitely would be ramping up in the second half of the year because that's when we said that we'll start seeing the ethane sustainably coming out in the second part of the year as we go forward. But I think as we come into the second quarter as I think we will start seeing this cross the 800, a lot depends on the growth out of the SCOOP and the STACK. We're seeing a lot of great results today and we are seeing some of those, I mentioned some volume growth out of the Permian and then the Williston Basin still comes on strong for us as well. We see that throughout the year. So I think an answer to your question is going to be much more second half with your ethane and these plants continue to ramp up but will probably cross 800 in the second quarter.

Okay, that's helpful and just if I could just switch gears on one other area, just I am assuming more of a question for Derek, you're in the cading gets us four times leverage in the next 18 to 24 months or so and our assumption has been such it's primarily an EBITDA growth story in that regard not really dependent so much on equity issuance. So, if you could just sort of clarify for us how you think you're getting there that would really be helpful?

Sure John, this is Derek and you are exactly right. I think we don't need to issue equity in order to get the leverage metrics down into that target range of four times. Now certainly we could depending on additional capital projects. If we have some large capital projects we could issue some equity there but really don't have the need to do so in that 18 to 24 months as we're thinking about it today.

Okay, that's helpful and just last one, just in the deck you provided to us Terry there was the optimization, marketing price differential, you indicated there were some squeezing going on there, how should we be thinking about that going forward?

John, definitely in the fourth quarter the spreads were narrower than we've seen in the third quarter and also the structure of the market that we get a lot of our marketing activity was narrower than we've seen. But as we move into the first quarter we've already seen the spreads between come and go it would be a lot wider than in previous years. We're seeing propane at $0.08 to $0.10 and butane at $0.12 in February and a little bit narrowing in March but still very strong. So I think that we will have a very good optimization in the first quarter.

Okay, that's it for me. Thank you so much for the clarifications.

Thank you, John.

Moving right along, we’ll take our next question from Kristina Kazarian with Deutsche Bank. Please go ahead.

Afternoon guys, so just a quick follow up for clarification on John's point, so that 17 millionish that you guys refer you on page eight in the slide deck, did I just get that right that you said that that's already worked itself out and probably won't be a go forward impact that we should be thinking about?

The 17 million is compared to the third quarter and most of that is in the marketing book. We had a very good third quarter in the marketing but we're definitely seeing wider spreads today than we saw in December as we continue to go through that. So we'll definitely have -- should be better off in the first quarter maybe different within the fourth quarter.

Perfect, so a bigger picture question you know, there's been a theme of we’re starting new projects and I know you guys had some delayed projects and you also talked about that 1.4 bcf type of takeaway capacity out of SCOOP and STACK, can you just remind me how much a pipe like that would cost, what you know catalyst to watch for on it moving forward in other new projects that you might think about coming back into the queue?

Sure Kristina I’ll let Phil to take that question.

Sure Kristine, the pipeline that we're trying to develop out of the SCOOP and STACK is 200-210 miles of 36 inch pipe with compression and depending on what kind of capacity sales that we are able to garner in the discussions it can be between $750 million and $900 million

And then other projects that you guys might think about moving back into the queue maybe some of the ones that had been delayed before the cycle turn down or anything else on your radar there?

Yes Kristina I think that you're thinking about it right. As we think about this 1.5 billion to 2.5 billion of projects under development there's a pretty good portion of it in our gathering and processing segment where we're adding additional capacity more around the SCOOP play and then certainly along the lines of the types of projects that Phil’s talking about specifically in the pipeline segment. But also opportunities in the Permian NGL related infrastructure, NGL storage, those types of things when you think about how it's broken up at a $2.5 billion level you're roughly talking about a third, a third, and a third, that is a third G&P, the third pipes and third liquids. And so generally that's how you think about -- that's what the that's what the projects look like that are currently under development.

That’s really helpful and last one from me, can you -- I know you guys get this a lot, but can you just remind me of your thoughts especially post the transaction we announced earlier this year of appetite for strategic M&A and how you might think about using the currency?

Sure, certainly we have an appetite for M&A we've got an appetite for asset acquisitions as well and in the things that the transaction certainly provides a benefit to our currency. And we are continually thinking about strategic M&A and what assets that we don't have that would certainly make sense. So, the challenge remains finding something that's actionable and if you do find something actionable trying to find something where the bid has spreads not so wide. So those challenges remain but certainly as a result of this transaction we’re very interested in acquisition opportunities.

Perfect, thanks guys for the update.

Thank you.

Thank You. Our next question comes from Eric Genco with Citi. Please go ahead.

Hey, good morning. Just wanted to follow up on the last question, you think about the guidance numbers, it looks like you're more than buying on fractionation capacity for 2017 and maybe into 2018 but if we were to look out a little bit and think about some of the higher end of guidance and how some of that could go, I mean how soon do you think you might need some new fractionation capacity, do you think about top end being 6.35, 1.40 for ethane, you get the 7.75 and you talked in the past about 100,000 barrels incremental from SCOOP STACK like how soon could that occur and how long it will be time to get some of those things in?

Well it usually probably take us about two years to get a frac for that standpoint and I think we won't need additional frac capacity until we get into 2019. Some of the people we've talked about out of the SCOOP or the STACK we are talking about dish transporting their barrels maybe not doing a complete frac, complete bundle service. So you kind of play that into as well but I think it will be 2019 before we would really think we need to look at additional frac capacity.

And how about on the processing side?

Eric on the processing side, again a lot of it will depend on the ramp that we see. As Terry mentioned we have seen pretty significant uptick in rigs in the STACK. That area, those wells are much higher volume than we see in the Balkan. If that type of activity continues we're going to need some additional capacity probably in the next couple years. So because we will eat up our available capacity pretty quickly. As we think about the Williston we got a couple hundred million a day of capacity available there. We also have the opportunity for some low cost expansions so you're probably looking at maybe three to four years before we would get in with current type pricing environment where you would fill up our capacity and may need additional processing.

Okay, and then last one real quick you mentioned the higher rates being somewhat in the G&P somewhat due to some higher IP wells coming on but I was just curious you could expand a little I mean, believe there was a contract settlement one of the customers in the Balkan and I was also curious to see if there was any sort of movement on perhaps the Mid-Con and getting any momentum there and maybe getting a little more money there?

Eric, this is Kevin again. That rate did spike a little bit in the fourth quarter. We did reach agreement on a restructured contract that was relatively sizable that drove that up a little bit. But we also had a significant amount of IP Gas come on in the fourth quarter which kind of drove -- which did drove up -- drive up our volumes and the vast majority of that gas was on contracts that were -- had a much higher fee based component. So quarter-to-quarter we think that rate will settle in more than $0.80 range as other volume comes on and just the volume mix on the contracts moves around a little bit. Now that is completely separate from the $8 million contract settlement was a service contract that is unrelated to our producer, our customer contracts.

Okay, alright well thanks a lot and congrats on your promotion.

Everybody I want to just make a just a quick correction, I guess I got tongue tied in one of my numbers when I was talking about Mid-Continent. Natural gas volumes I said 790 million cubic feet per day periodically and what I meant to say was 690 million cubic feet per day so perhaps that was a wishful thinking on my part but anyway my apologies. So hopefully that clarifies it and we will make sure the transcript appropriately reflects the corrected number. Thank you. Now back to questions.

Our next question comes from Michael Blum with Wells Fargo. Sir, please go ahead.

Hi, thanks. Can you provide update on where you stand on the West Texas LPG line and then just how that sort of interplays with, sounds like you're connecting some additional plants in the Permian and do you have enough takeaway capacity and it just kind of you know update in terms of your thoughts on NGL takeaway capacity and just any update on West Texas LPG?

Sure. Michael, this is Sheridan. The West Texas rate case we will be in front -- we have a hearing in front of an administrative law judge at the end of March and then after that it will go through its normal course to come to a resolution on that. In terms of how that impacts the new plants we are connecting, we are able to contract these new plants at market rates not at the lower rates due to the -- that is what the market is out there. So as we increase the volume out there we'll get it at a higher rate. The capacity that we have is we're talking to many different plants out there and some much further than others and we think that through those discussions there is a distinct possibility of an expansion coming on the West Texas pipeline out of the Permian Basin as that continues to grow. So that will be depending on how successful we are with contracting some of these new plants that will be up in the next year to 18 months.

Okay and that expansion would that be at the other end like timing or is that just pumps and cost and I'm just trying to get a feel for what that would entail?

Well, definitely it will be cheaper than laying a new line but it will be in some pumps and some little bit of looping up some of the line and there probably be some additional gathering infrastructure out to the Permian.

Okay, great. And then the other question Terry I think I heard you say earlier that in the 2017 guidance assumes $40 million to $60 million EBITDA uplift from ethane recovery, did I hear that right?

That's correct.

Okay so, I feel it was about a year ago you guys are talking about the potential for $200 million EBITDA uplift from ethane recovery. When do you think that could occur?

Well, certainly that happens over time and that $200 million EBITDA impact that is still a good number. The timing is 2017, 2018, and 2019 impact. So the cumulative effect of all the incremental ethane coming on would have an impact of $200 million. So that's all still -- that is all still -- well still works. So that's the timing bit. 2018 is a big year for the petrochemical facilities starting up with as we said earlier in the call we've got three large crackers coming on that are going to crack anywhere from 80,000 to 100,000 barrels a day a piece of ethane. So of course that's pretty big and a million barrels a day ethane market and then we have been significantly more crackers starting up in the 2018 timeframe. So we expect significant uplift in this business as we think forward in this NGL segment. The uplift from ethane continues to be a big part of our story in addition to all the raw feed growth that's happening in the STACK and the SCOOP and in the Permian.

Great, thank you very much.

[Operator Instructions]. We’ll take our next question from Christopher Sighinolfi. Please go ahead with Jefferies.

Hey Terry, thanks for taking my question

You bet Chris, how are you?

I am well, thanks. I just want to follow real quickly maybe on where Michael left off so just to understand so 40 to 50 is what's in the guidance for this year. Sheridan I think was mentioning you're still anticipating that to be mostly back half loaded. And so I guess I'm just wondering do you still see sort of the regional profile that you've outlined before where we should expect sort of all Permian to be recovered and then we move to Mid-Con for the next sort of tranche of recovery?

Yes Chris, that is right. The Permian will come first and then we'll go into the Mid-Continent but I will say that the rates out of the Mid-Continent aren’t very far behind the Permian. They're very close to each other so they could -- you could see a little bit come out Mid-Continent first depending on which power contracts are structured. But that's basically on a high level, that's what we see happening.

Okay and then there was a question earlier about frac capacity within ONEOK franchise and we've obviously seen some frac announcements now first time in a while. And I know that some others at Bellevue remained permanent. You had mentioned Sheridan potential for you to transport volumes on behalf of potentially what others might frac. Can you just talk to us a little bit about that dynamic and I how you think it might take shape, you know vis-à-vis the producer schedules and then also you know this recovery dynamic?

Well in terms of just transporting out of the SCOOP and the STACK we have some customers out of the SCOOP and the STACK that have frac capacity and they wanted to fill their frac capacity first. And so that's why we were working with them to just do a transport only type of deal. In terms of our frac capacity I would like to see what comes out of the SCOOP and the STACK, there's an opportunity to fill the existing capacity we have today and obviously ethane is going to flow that capacity as well. But we are very excited that we think as we go forward and look into 2019 and beyond that there is opportunities as the Permian grows, as the SCOOP and STACK grows that we may have a frac coming on but all is going to depend on commitments from the producers and processors I'm going forward.

So, just the only thing I would add to that Chris is that from an ethane perspective we have the capacity necessary to reap this $200 million impact, EBITDA impact from incremental ethane. So that capacity, our deethinizers are underutilized right now as a result of the ethane rejection. So there's no capacity that has any meaningful size and needs to be built to accommodate that. What Sheridan's primarily talked about is the raw feed or C3 plus capacity that needs to be constructed to accommodate this organic growth not just out of the STACK and the SCOOP but certainly out of the Permian. We expect to be a fractionation service provider for customers in the Permian even though currently many of our customers frac in other locations. As we bring on the incremental development that's happening in the Permian we expect to be providing the full menu of services these customers are gathering fractionation and certainly storage as well.

Other thing I would add to that is that we as well also have fracs permitted in Mount Bellevue so when we get the commitments we will be able to start building fracs.

Okay, I was more curious like somebody was signing up for new frac capacity I guess chances are that's under a fairly lengthy commitment so I was just wondering if then somebody is looking to take pipe capacity on your system to sort of provide the volume that would subsequently be frac if you would get sort of an equal duration contract or how that might work and I know you've had sort of a sterling three expansion opportunity out there for a while like at what point you might maybe see that fall back into reality kind of to Kristina's earlier question?

I think really as we talk about people that we may be transporting out of the SCOOP and the STACK they’re predominantly be going into their own fracs that they own. They would be doing it but and so we negotiate on those transportation deals independently if they're going to take it to a third party frac, we negotiate those independently. So we'll go after the link that term that we think is appropriate for our business here regardless of what they get on the frac side. Some people have done shorter term frac deal, some people have done longer term frac deals, and some of the other volume that we transport only.

Okay and then if I could really quickly Sheridan just to clarify something you had said earlier in response to question so if I think about the profile of where you are anticipating C2 volumes to be recovered, you kind of have this profile of cost structure if you will. And what you were saying that if I heard you correctly some regions within the Mid-Con are competitive relative to the Permian. We would see that rate sort of -- that volume hit first and then we profiled sort of in a rising cost water flow, is that the right way to think about it and then where would -- I guess where does the -- you've noted a bundle fee on the Permian of like less than $0.03. I mean that's kind of like the ballpark you're talking about then in terms of the lowest cost areas of the Mid-Con?

No, the $0.03 that we have talked about is an overall fee on the West Texas pipeline at the lower rates that we are at today. The most of the other pipelines are at a much higher rate and that higher rate is where we see is comparable to the Mid-Continent. So if you just look at what we've provided we've provided $0.08 a gallon on an average fee out of the Mid-Continent. And so that we feel that fee is competitive with some of the fees that are out of some of the new plants that are out of the Permian that are on the newer pipelines which are at a higher rate than our normal pipelines.

So Sheridan the rates, the $0.03 and $0.09 that you're referring to are transportation only, they do not include fractionation correct?

The $0.03 yes, it’s definitely transportation only it is an average fee for the whole West Texas pipeline. That takes in Permian, Barnett Shale, East Texas, short haul volumes. So it is an average across that whole thing. Obviously Permian is going to be on the higher state even on our system. $0.08 out in the Mid-Continent is an average fee that has both transportation and transportation in frac. But could also go to [Indiscernible] different places but we see -- as you talked about certain contracts in the Mid-Continent we know are competitive with some of the new plant out of the Permian.

Okay, that's very helpful. Thanks for the clarification.

You bet. Thank you Chris.

And it appears there are no further questions at this time. I’d now like to turn the conference back over to our presenters for any additional or closing remarks.

Thank you our quite period for the first quarter starts when we close our books in early April and extend till earnings are released after the market closes on early May. Thank you for joining us.

That does conclude today's presentation. Thank you for your participation. You may now disconnect.