T.D. Eureste - Investor Relations Terry Spencer - President and Chief Executive Officer Walt Hulse - Executive Vice President of Strategic Planning and Corporate Affairs Derek Reiners - Chief Financial Officer Wes Christensen - Senior Vice President, Operations Sheridan Swords - Senior Vice President, Natural Gas Liquids Kevin Burdick - Senior Vice President, Natural Gas Gathering and Processing Phillip May - Senior Vice President, Natural Gas Pipelines

Eric Genco - Citi Brian Gamble - Simmons and Company Danilo Juvane - BMO Capital Markets Christine Cho - Barclays Craig Shere - Tuohy Brothers Becca Followill - US Capital Advisors Shneur Gershuni - UBS Jeremy Tonet - JPMorgan John Edwards - Credit Suisse

Please stand-by, we are about to begin. Good day, ladies and gentlemen, and welcome to the First Quarter 2016 ONEOK and ONEOK Partners 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. T.D. Eureste: Thank you, and welcome to ONEOK and ONEOK Partners’ first 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, Chief Financial Officer; and Senior Vice Presidents, Wes Christensen, Operations; Sheridan Swords, Natural Gas Liquids; Kevin Burdick, Natural Gas Gathering and Processing; and Phil May, Natural Gas Pipelines. I'll begin with a few opening remarks, then Derek will give a brief financial update and then I will wrap up with highlights of the first quarter, our outlook for the remainder of the year and our ethane opportunity. To begin, first quarter 2016 performance was a result of the progress made last year by continuing to focus on increasing our fee-based earnings, reducing commodity price risks in our businesses, project execution and making prudent financial decisions all while continuing to operate safely and responsibly. In this challenging market conditions, we have relied on our strengths, which for ONEOK Partners are predominantly fee-based earnings, our uniquely positioned assets and our dedicated employees. Our competitive advantage is our integrated network of assets that fit and work well together. Our 37,000-mile network of pipelines, processing plants and fractionators are well positioned to withstand the cyclical nature of the industry. Our assets in the Williston Basin have served us well, and we continue to benefit from the basin's large natural gas reserve base and inventory of flared NGL-rich natural gas. Our Natural Gas Pipeline segment remained well positioned to expand its fee-based natural gas export capabilities, particularly to Mexico where we have key relationships through our joint venture Roadrunner Gas Transmission Pipeline and our extensive Natural Gas Liquids business maintains a growing position in the Rockies, Texas and emerging STACK and SCOOP plays in Oklahoma, providing us a large and diversified base with which to serve our end-use customers. The partnership's distribution coverage increased to 1.06 times in the first quarter, up from 1.03 times in the fourth quarter 2015 and significantly higher compared to the beginning of 2015 which is a reflection of our increasing stable cash flow as we now have a significant amount of infrastructure completed and are able to harvest earnings, particularly in the Gathering and Processing and Natural Gas Liquids businesses. ONEOK Partners first quarter 2016 adjusted EBITDA of approximately $445 million represents a nearly 40% increase compared with the first quarter 2015. Executing on our growth projects, contract restructuring, capital and cost savings and consistent operations were key drivers to delivering the greatly improved results from a year ago, even in the face of deteriorating industry fundamental throughout 2015. From an operating perspective, volume growth across our businesses, increased fee-based earnings, and ongoing cost reduction efforts across ONEOK Partners business segments have all contributed to a solid first quarter and positive outlook for the remainder of 2016. In the midst of some of the industry's most challenging conditions, our employees once again performed exceptionally well by successfully executing on our strategies to mitigate risk, reduce capital spending and operating costs, and manage our balance sheet. It is through their hard work and determination that our company delivered impressive results quarter after quarter in 2015, and we remain as committed as ever to delivering even better results in 2016. Through our key strategies and well managed and operated assets, our employees have, with a high sense of urgency, met the challenge, just as they have many times in the past. I'd like to thank them for their hard work and commitment to deliver value to the bottom line safely and reliably. We’ll cover each of the segments in more detail later in the call, but first I'd like to have Derek give us some brief financial update. Derek?

Thanks, Terry. Both ONEOK and ONEOK Partners ended the first quarter in a strong financial position with healthy balance sheets and ample financial flexibility. As Terry mentioned, ONEOK Partners first quarter distribution coverage was 1.06 times. ONEOK's first quarter dividend coverage was 1.31 times, which together with cash on hand entering the year maintains ONEOK flexibility to provide financial support to the partnership if needed. In yesterday's earnings news releases, we maintained our 2016 financial guidance expectations for both ONEOK and ONEOK Partners. Our proactive financial actions in 2015 and early 2016 and enhanced earnings from the partnership has allowed the partnership to deliver on distribution coverage, while also reducing leverage. The partnership's capital expenditure guidance remains $600 million, including $140 million of maintenance capital for 2016, as the reliability and integrity of our assets is the foundation of our success. However, we are seeing aggressive bidding from our vendors on maintenance projects and the timing associated with our maintenance activities can vary significantly from quarter to quarter due to seasonal impacts in varying maintenance cycles across our ever-changing asset base. Typically our maintenance capital spending is lower in the first quarter. Sequentially maintenance capital decreased $8 million in the first quarter, primarily due to our maintenance project plan for the quarter having fewer projects compared to the fourth quarter, which is not unusual when compared to our historical spending profile. We are on plan for our scheduled maintenance projects for 2016. Similarly, as it relates to operating cost, we continue to see competitive, lower pricing and rates from service providers and we have significantly reduced contract labor across all of our segments. In the first quarter we realized $15 million sequential decrease in operating cost. And as Terry mentioned, we continue to focus on internal operating cost reduction efforts company-wide. We expect these cost savings to continue throughout the year. In January, ONEOK Partners entered into $1 billion three-year unsecured term loan, effectively refinancing our 2016 debt maturities and enhancing financial flexibility. With approximately $1.9 billion of capacity available on the ONEOK Partners credit facility at the end of the first quarter, the reduction of more than $2.2 billion in capital growth projects in two years and higher earnings, the partnership does not need to access public debt or equity markets well into 2017. The partnership continues to progress towards deleveraging as our trailing 12 months' GAAP debt to EBITDA improved to 4.5 times at March 31st. And we continue to expect annual GAAP debt to EBITDA ratio of 4.2 times for the full year 2016 as a result of prudent financial, operating and commercial execution. As always, we remain committed to the partnership's investment grade credit ratings. On a standalone basis, ONEOK ended the first quarter with nearly $130 million of cash and expects to have approximately $250 million of cash by year-end 2016 and an undrawn $300 million credit facility, allowing us financial flexibility as we continue to navigate a challenging market environment. In February, we provided detailed information on our counterparty credit risk. We’ve included similar information again this year in our Form 10-Q but there haven’t been any substantial changes. We have a very high quality customer base and no material counterparty credit concerns. The majority of our top customers are large petrochemical and integrated oil companies, which have a higher tolerance for volatility and commodity prices. Our track record of prudent and proactive financial decisions during uncertain times resulted in ample liquidity, too strong balance sheets, and a strong customer base. ONEOK and ONEOK Partners remain well positioned to withstand a volatile commodity and financial market environment. Terry, that concludes my remarks.

Thank you, Derek. Let's take a closer look at each of our business segments. In the Natural Gas Liquids segment, volumes continued to increase year-over-year with first quarter 2016 volumes gathered up 6% and volumes fractionated up 16% compared with the first quarter of 2015. Compared with the fourth quarter 2015, volumes gathered and fractionated were lower primarily due to decreased spot volumes, higher ethane rejection and seasonal impacts. We continue to expect NGL volumes to be weighted toward the second half of the year as incremental volumes from new natural gas processing plant connections continue to ramp up. In the first quarter, we connected three additional third-party plants to our NGL system and we continue to see volumes ramp at the eight plants we connected in 2015. We expect to connect one additional third-party plant this year in addition to completing and connecting our 80 million cubic feet per day Bear Creek plant in the Williston Basin where additional flared natural gas remains ready to come online. Williston Basin NGL volumes, our highest margin NGL volumes with bundled rates more than three times of those in other regions, remained strong in the first quarter. The average volume gathered on our Bakken NGL Pipeline increased nearly 12% compared with the fourth quarter 2015, driven by the completion of the Lonesome Creek plant in November 2015 and compression project. I'll also talk about ethane and provide an update on our ethane opportunity outlook in just a moment. As it relates to the West Texas LPG system, in July 2015, we increased rates on this system to be more in line with market rates. In March, the Texas Railroad Commission suspended the rate increase until it is determined by the Commission if the rates are in line with the market. We are confident that our increased rates are just in reasonable and in line with the market. However, regardless of the outcome of the pending case, our current 2016 financial guidance remains as indicated. As you all can appreciate, due to the legal process now underway with the railroad commission, it will not be prudent at this time for us to discuss this case in any more detail. We will provide future updates or commentary when and if it is appropriate. In the Natural Gas Gathering and Processing segment, Williston Basin volumes were a key driver to our first quarter performance. Our Natural Gas volumes processed reached 810 million cubic feet per day as we captured previously flared gas and connected new wells to our system. Average natural gas volumes processed in the Williston increased 44% in the first quarter 2016 compared with the first quarter last year, and increased 6% compared with the fourth quarter 2015. Our producer customers continue to drive improvements in initial production rates through enhanced completion techniques, and combined with the higher natural-gas-to-oil ratios in the core areas where virtually all of our new wells are being connected, have helped offset the reduction in drilling and completion activity. We will continue to benefit from more than 820 wells connected in 2015 and the 115 wells connected to our system in the first quarter 2016. The vast majority of these high performing wells are in the most productive areas of Williams, McKenzie, and Dunn counties in North Dakota where we have more than a million acres dedicated to us and an extensive network of interconnected gathering lines, compression, and processing plants. There are currently 900 drilled but uncompleted wells in the basin, with nearly 400 on our acreage. We saw a decline in the drilling rig count across the Williston Basin during the first quarter and currently have approximately 15 rigs operating on our acreage under dedication. Flared natural gas in North Dakota was reported at approximately 185 million cubic feet per day for the state in February, with approximately 70 to 80 million cubic feet per day on our system. This continues to present an opportunity for us as we add processing capacity to our system in the third quarter 2016 with the completion of our Bear Creek natural gas processing plant. In the Mid-Continent, first quarter 2016 processed volumes increased 8% compared with fourth quarter 2015 volumes. Similar to the Williston, our producer customers continue to drive significant increases in initial production rates through enhanced completion techniques, especially in the STACK, Cana-Woodford and SCOOP plays. Procedure delays on completions of some large multi-well pads are expected to impact our volumes over the next several months and potentially through the remainder of 2016. However with the recent improvement in commodity prices and breakevens in the STACK competing favourably with the best plays in the country, we could see acceleration of the delayed completions. Contract restructuring in the Natural Gas Gathering and Processing segment has significantly decreased the segment's commodity price sensitivity and was another major contributor to the partnership's first quarter results. The segments average fee rate increased to $0.68 per MMBtu, compared with $0.35 in the same period last year and $0.55 in the fourth quarter 2015. We expect the segment's earnings to increase to more than 75% fee-based this year, driven by this contract restructuring efforts. Moving on to the Natural Gas Pipeline segment, first quarter results remained steady as the segment continued to provide the partnership with stable, predominantly fee-based earnings. The segment completed two capital growth projects in March, the first phase of the Roadrunner Gas Transmission pipeline project and a compressor station expansion project on our Midwestern Gas Transmission pipeline which will add an additional 170 million cubic feet per day of capacity to the pipeline. The Roadrunner project is fully subscribed under 25-year firm fee-based commitment and the second phase of the Roadrunner is expected to be complete in the first quarter 2017. Additionally, the Midwestern Gas Transmission expansion is also fully subscribed under 15-year firm fee-based commitments. Our Natural Gas Pipelines segment is primarily market connected, meaning we are directly connected with large stable customers who provide services to end users. These customers such as large utility companies, electric generation facilities and industrials have specific volume needs that don't fluctuate based on commodity prices. Additionally, we work closely with these customers to design our systems to fit their specific needs. Unlike basis-driven pipelines, there is minimal financial risk associated with our Natural Gas Pipelines or our customers. We like the stability of our Natural Gas Pipelines business and the customers we serve, and we'll continue to develop additional fee-based and market-driven long-term growth and export opportunities in and around our asset footprint. I'd like to close by providing an update on our ethane opportunity outlook. For the past three years our industry has experienced an unprecedented period of heavy and prolonged ethane rejection. The partnership continued even in the face of sustained ethane rejection to increase our Natural Gas Liquids volumes gathered and fractionated. We are starting to see ethane prices improve in relation to Natural Gas as a result of improving NGL prices and weakened natural gas, increases in NGL exports and expected incremental ethane demand from new world scale petrochemical crackers. Since last quarter, we've seen ethane recovery economics improve. Some natural gas processing plants on our system have intermittently started to recover ethane, which we expect to continue throughout 2016. We continue to expect a meaningful amount of processing plants to move into full recovery in early 2017. We average 175,000 barrels per day of ethane rejection on our system in the first quarter, and we expect anywhere from 175,000 to 200,000 barrels per day of ethane rejection on our system as new natural gas plants, we are connected to, continue to ramp up, and as we see the impacts of increased volumes in the Williston, STACK and SCOOP plays throughout 2016. We are well positioned to benefit from this ethane opportunity and have more than enough infrastructure to bring these incremental barrels or approximately $200 million in annual earnings to our system with no additional capital requirements. We also have the opportunity to utilize our assets to capture pricing differentials if any dislocations in pricing occur between the Conway, Kansas and Mont Belvieu, Texas market centres as a result of increasing ethane demand. Ethane recovery presents a major opportunity for ONEOK and ONEOK Partners, but it certainly isn't our only opportunity. We remain focussed on additional fee-based growth opportunities for our businesses, cost effective ways to enhance our assets, and employee retention efforts. So we are fully prepared when market conditions improve. Congratulations to our employees on a solid first quarter. We continue to face headwinds from challenging industry conditions, but we've shown once again that we're uniquely positioned to handle these challenges and deliver on the financial results we've laid out for ourselves and our investors. Thank you to all of our stakeholders for your continued support of ONEOK and ONEOK Partners. Operator, we're now ready for questions.

Thank you sir. [Operator Instructions]. We'll pause for just a moment to allow everyone an opportunity to signal for questions. And we will take our first question from Eric Genco with Citi.

Hey, good morning. I have a couple of follow-up questions on ethane. Just wanted to kind of go over. I think you mentioned it basically, but in moving to 175,000 to 200,000 barrels a day of ethane opportunity in '16 versus the 150,000 to 180,000 last quarter being rejected, is that basically -- that's basically third-party plant and a shift towards more liquid rich drilling overtime, is that what's accounting for that increase?

Yes, Eric I think, yes, most of that is a result of the new plants that we've connected here fairly recently. And, of course, the growth that we're seeing behind those facilities that we indicated in my remarks, so, yes, most of that is from the new plants. Sheridan, anything?

No, that's it.

All right. And I guess the other thing I was kind of curious about is we’ve been sort of talking about this little bit more, just trying to get a better handle on some of the ethane recoveries that are likely to come out of the Bakken eventually. And so I think I understand based on bundled costs and how that works economically, and you guys have said that basically that Bakken would theoretically be one of the later basins to be culled. But I'm also curious too because I know -- you know, you've referred to some of your services being non-discretionary in the past and it's not like ethane economics specifically is going to drive drilling in the Bakken. So I'm curious is there a way to look at or think about pipeline stacks in the Bakken and sort of -- you know, as things come back, just sort of push ethane recovery and how that might impact you. Is there any way to sort of numerically think about that or is that still something that will just have to kind of wait beyond?

You know, Eric, broadly as you think about where we deliver ethane across our systems, we really don't have any quality issues or any concerns really on a large scale. We may periodically in certain specific locations dependent upon the location of those pipes to end-user, we sometimes do have some issues with respect to quality specs, but I don't see quality specs being a big driver for ethane emerging from the Bakken, nor really anywhere else for that matter. And when we talk about these non-discretionary services, we talk about producers have to have the process and they got to have the liquids extracted from the gas in order to meet quality specs. Ethane tends to be one of those -- is one of those NGLs that can be -- can easily go into the gas train and be diluted without causing much of a problem, unless you've got industrial customers or commercial customers right near -- located in pretty close proximity to the processing plant, okay? That helped you?

Yes, it does. Thank you very much. I appreciate your time.

And we will go next to Brian Gamble with Simmons and Company.

Good morning, everybody.

Good morning, Brian.

On the Natural Gas Gathering and Processing segment, that fee rates increase obviously excellent year-over-year and even quarter-over-quarter. I know that we'd talked about some of those new contracts hitting in January and that creates a bump. Maybe you could walk us through how we should think about that rate moving through the year. I think there is some contract that come up mid-year, maybe some Mid-Con things. But if I remember correctly, there was a pretty healthy chunk of the Williston that they got repriced? And just want to make sure, being realistic about how I'm thinking about that rate for the rest of the year.

Yes, I'll just make a couple of general comments and I'll turn it over to Kevin. You know, as far as our contract restructuring effort, the lion share of the contracts or the bulk of what we set out to do in the Williston Basin, that's done. And so don't expect a whole lot more to occur. There's still some work in progress, but don't expect a whole lot more impact from that. The Mid-Continent is just going to continue to be work-in-progress. We have a much larger producer base of, that is, we have a lot more procedures that have much smaller volumes and consequently it takes -- it's a lot more involved in the Mid-Continent than in the Williston, just because of the sheer number of contracts that we're talking about. So that's caught from in a broad sense. Kevin, you've got anything else to add to that.

No, I think that's right on.

That works. And then as far as the connections in the Williston, you mentioned 115 wells, I believe, you said in Q1. You mentioned the flared gas that's still on the system as well as the potential duct completions that would go in. But as far as well count adds that you’re anticipating for the rest of the year, are there wells that are completed that are sitting there that now the system can handle that we’re working on, or are we waiting for ducts for the majority of the opportunity to, I guess, incrementally add new wells to the system more for this year?

Brian, this is Kevin. Yes, that will come from -- the way we think about connecting the wells, it will come from a couple of -- from both of those places. I mean as rigs continue to work the basin as those wells that are being drilled or completed, we’ll connect those up. But there is also the backlog of ducts that are on our acreage that as we communicate with producers and realign the schedules, we'll connect those as well. So our future -- our 2016 connections will come from the combination of both of those. And we still expect we'll be in that 250 to 350 range for total connects for the year.

That delta between what we’ve done so far and that midpoint of the range, so call it 185, how should I think about that as far as the buckets are concerned. Just I mean broadly speaking, can you give me a percentage breakdown between the two?

Broadly speaking, it might be half and half.

Great, that's helpful. I think that's it for me. Appreciate it you guys.

Thanks Brian.

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

Good morning.

Good morning.

You guys obviously seeing sort of an increase in your fee-based gathering margins here for the rest of the year. So as you think about guidance for 2016, is the sort of pending issue with the rates in West Texas LPG the only downside risk that you see to this year's guidance?

You know, as far as West Texas, as I said in my comments, I'm not going to go there for obvious reasons. But you know, as we think about our fee-based activities, we have certainly taken out a lot of risks, okay? And so -- and as far as renegotiation of contracts, we've been successful at increasing our rates across the board, okay, not just in the NGL space but in the gathering and processing space in particular. So, you know, as we move forward we really don't see any -- we don't see from a rate standpoint backing up anywhere. Okay?

Got you. Over the last couple of months, we've seen sort of more bullish NGL sentiment in general. How do you guys think about continuing to reach special contracts given that some of the part exposure that you've had before sort of is rebounding right now. Is there a percentage that you're targeting of fee-based versus commodity?

I'll make a general comment. You know, we don't have a specific target for any of our businesses in terms of, this is how much fee-based margin we want to have. Obviously, we want to have as much fee-based margin as we can possibly get. And obviously we're continuing to push on that re-contract and negotiate everywhere we can, certainly bringing new assets and new businesses to the table or new opportunities to the table that are fee-based. When we think about the reduction of risk, we think about it more from a coverage standpoint, okay? What do we need in this business, what do we need in this business segment in order to maintain an appropriate coverage level for each one, and certainly an appropriate coverage level for the entire entity. So that's kind of how we think about it. Sheridan, do you have anything you want to say about our contracts in NGLs?

Well, I think the thing that comes out is even in NGL's we're continuing to change our optimization exposure into fee-based, and we will continue to do that even in widening the spreads. When we say widening spreads, we think that's even a better opportunity to start locking in margins. So as you said, we always want to go to more fee-based and take our commodity exposure out.

Got you. Last question for me. You mentioned coverage being a big reason as how you're managing some of these contract restructures. Is there a target coverage ratio that you're looking at long term?

Well, certainly, as we've said in the past, you know, at the partnership, 1.1 to 1.15 longer term is a coverage that you know, it could make some sense for us, potentially higher. But certainly as we've driven the risk out these businesses, we don't have to maintain this quite as big a coverage. But that's kind of how we think about it.

If you take that statement and sort of think about what you're thinking about sort of your debt metrics, where do you see yourself being more comfortable starting to bump distributions?

Well, certainly we've told you 4.2 times debt to EBITDA ratio is what we're targeting, but we really would like to be sub-4. I mean, ideally that's where we'd like to be. And that's the longer term plan.

Okay. Thank you. That's it for me. Thanks.

You bet. Thank you.

And we will take our next question from Christine Cho with Barclays.

Hi, everyone, congrats on the quarter.

Thank you.

When I look at how much ethane is being rejected on your system, the capacity of your NGL pipes and the utilization on those pipes, I have that your pipes are going to be full once all of the ethane behind your system is extracted. Can you talk about the expansion opportunities on the Sterling and Arbuckle line compression or looping? Would you charge a similar rate as you are now? And is it safe to assume that the economics of an expansion, if through compression, is going to be better than the 5 to 7 times multiple you usually give out?

Christine, what I would say is that we feel that we have enough capacity on our existing pipelines to handle the ethane that's being rejected, but it will push the utilization of those pipelines to pretty high rates. If we get to the opportunity to expand our pipelines, the cheapest expansion is sitting on Sterling 3 and we had said we can take that up 60,000 to 70,000 barrels a day with relatively inexpensive pump stations on there, which would be at a very high multiple to add that kind of space for a very little capital. The other pipelines Arbuckle and the other two Sterling pipelines are fairly expanded with cheap expansion. It would be inter-looping, so it still would be much cheaper than laying a new line but it would be more expensive than what Sterling 3 has. But we think right now we can handle all the ethane that could potentially come out of our system.

Okay, and then just piggyback on that, I mean, I have that ethane demand that's going to be 800,000 barrels per day if we include the ethane export projects along with the cracker additions. Obviously, we've been thinking that in the near- and medium-term ethane price is going to go up to equate methane equivalent plus CNF. But do you think over the longer term, we could be short ethane, this would imply that ethane price could approach naptha prices?

Christine, I think what would happen is that first thing if ethane prices increase, you're going to run into the other LPGs that can be cracked, especially in the existing cracker. So you're going to hit into propane, butane, and natural gasoline before you get to naptha. So I don't think we'll see in the long term ethane prices approach naptha prices. I think propane and other ones will put a lid on the price of ethane.

Okay. And then last one for me, very helpful, thank you. What's the average contract life on the NGL pipelines? And you've kind of mentioned this before, but I'm assuming that you have less optimization capacity than you did kind of at the peak, but as these contracts with customers come due, how should we think about how you guys decide whether or not to extend the contracts versus not renew it and maybe retain some capacity for optimization opportunities? Are you kind of happy with the levels that you have now or you want to decrease it, increase it?

Christine, what I would say is that these contracts that you're referring are contracts that we have with the processing plants. So it's a bundled service for not just transporting product to Belvieu but also for fractionating it as well. So what we would want to do is always continue to extend those contracts. And if we can get the right prices to take them into Belvieu, we would rather put them on a fee-based business than be open up to the spread between Conway and Belvieu. So if we could, we would contract the whole pipe if we could get it at good rates.

Would you say that the bundled rate probably has room to come up then?

Potentially yes.

Okay, and one more…

We would…

Go on, sorry.

Any time we look at the rates when we go out and look at a plant, we look at what the competition is, we look at how are our services that we provide and all that and try to price our services accordingly. So as prices continue improving going into Belvieu, I think there is some opportunity to increase our rates into Belvieu.

And what's the average contract life?

Most of our contracts, substantial amount of our contracts do not expire until we get into the 2020's. We do have a little bit that expires between now and then, but most of it is in the 2020's.

Okay, great. Thank you.

Thank you.

[Operator Instructions] We will take our next question from Craig Shere with Tuohy Brothers. Please proceed.

Good morning. Congratulations on another good quarter.

Thanks, Craig.

So I think you said 115 well hook-ups in the quarter, Terry. But guidance I think is still only 250 to 350 for the full year. And if I'm not mistaken one of your major customers has just added a frac crew on a farm to work done, that's duct inventory. Given all this, is your reiterated guidance for well hook-ups perhaps conservative?

Craig, this is Kevin. I don't know if I'd use the word conservative but yes, we've had a strong showing out of it for the first quarter. But then again, rigs have dropped off quite a bit as well during that same timeframe. So we continue to talk with our customers daily and understand as commodity price moves around, kind of their sentiment towards either adding frac crews or adding rigs changes a little bit. But right now, we feel good about that 250 to 350. If we have some more movement with producers that are going to accelerate completions in the Williston and then yes, that number could go up.

And on the remaining 70 million to 80 million a day of flaring on your Bakken footprint, any thoughts on maybe a run rate as we exit the year? Obviously, new well hook-ups will contribute to potentially some incremental flaring. So this isn't going to go down to zero. Any thoughts on where we could exit the year? And also over time, are we perhaps seeing the actual amount of flaring that's reported perhaps be on the conservative side so that you could get most likely higher uplift?

So, a couple of things there. One is as we look at our flaring, keep in mind, there is probably 30 to 40 million behind Bear Creek, so when we bring Bear Creek online, we expect that a chunk, approximately half of that will get put out with that -- as that plant comes up. As for the other, yes, there will always be some level of flaring that occurs, but we do have quite a bit and we’ve got some head room from both our field infrastructure and processing plants. So as new wells come online, I don't know that that would contribute much to the flaring. So I do think we expect that number will go down significantly as we move into the back half of the year once the Bear Creek is up. And yes, when you look at the numbers over the last few months, it does appear that some of the reporting has been conservative for overall -- for total kind of state-wide flaring.

Great. And on the ethane question, in terms of specs, I think I forgot when, it's some quarters ago, you had a 20,000 barrels a day of recovery to mid downstream Y-grade requirements. At the time I think you mentioned the possibility of that going away with the downstream solution, obviously still plotting margin for you. Could you see that margin opportunity expanding over time as the Y-grade growth out of the region continues?

Craig, this is Sheridan. The ethane coming out of the Bakken is for purely products specifications that we have downstream. And right now with the ethane we have coming out there now, we are able to manage that situation. As we continue to look forward, we are trying to find the most economical way to extract, to solve this solution in another way, but we're still looking at that. It's capital intensive. So we're still trying to work on with the right solution for that is. In terms of getting more ethane out of the Bakken for uplift there, we see the opportunity is there as increasing ethane prices with the new petrochemical facilities come online is where we think the most opportunity is.

Okay, great. And just a little more color around the NGL segment headwinds, including the $10 million decrease in exchange services and $5.6 million in marketing would be helpful. Maybe just more of a discussion about specific spot and about some volumes and about summarization and trends there.

Craig, the marketing was down mainly because we had a warm winter and also we had less volume from our marketing department going into refineries. We have already seen that tick back up as we move into the second quarter. The extreme services were down, it's because we had spot volume in the fourth quarter, we had a little bit more ethane rejection in the first quarter, and we had a little seasonal or weather effects also in the first quarter. Volumes that have already rebounded as we move into the second quarter and today our volumes on our gathering systems are at or a little bit above 800,000.

Great. And last question. Derek, on the favourable comments you had about favourable bidding for your maintenance CapEx and the falling OpEx cost, how much opportunity is there for further improvement in '16 and could you see these benefits continuing in the '17 or is it very kind of variable quarter to quarter?

Hey Craig, I'm going to turn it over to Wes Christensen to answer that question.

Yes, Craig. We continue to have contact with our contractors and find as they are looking for work to keep their crews busy, that there's opportunity there to improve it. We have already captured quite a bit from them through '15 and '16 and expect it to continue in the current environment.

Great. Thank you very much and congratulations again.

Thanks Craig.

And we will take our next question from Becca Followill with US Capital Advisors.

Good morning, guys.

Hi Becca.

Hi. On processing, guidance for the year is 1.9 to 2 for the year, but the quarter you were more like 1.95, and you talked about volumes being back-end loaded. Is that back-end loaded for NGLs? And you also have new processing coming on in a year or so, help me out with guidance relative to Q1.

So, yes, it is. We do have some back-end loading, in particular in gathering and processing because the Bear Creek plant coming on in the third quarter is going to fetch you there. And you're going to see some back-end loading a bit on the NGL side as well. Sheridan, you got anything to add.

Yes, I mean we do have plants coming online, the Bear Creek plant will add more to the NGL gathering. We have another plant in the Mid-Continent that's coming on. We just had a plant yesterday, start delivering -- a new plant start delivering into the West Texas pipeline asset. So here we are still little bit. We should see growth from here forth.

But you're already at the mid point of the guidance? That's where I'm coming from.

Becca, could you kind of clarify when you say the -- we're at the mid point of the guidance, which?

I'm looking at gas process, it was 1.948, I think your guidance was 1.9 to 2.

Okay. So that's -- again, we had a strong Williston volumes and that's in -- you're referring to the MMBtus and so that's driving that. The gas being much richer coming out of the Williston, so that's what you're seeing there. Our volume profile just at a high level in the Williston is going to be more flattish for the year. So that's the reason you're seeing that.

But you're also adding Bear Creek in Q3?

Right and that will open another -- again, that's 40 million a day in cubic feet. So when you're talking about the total, it's not going to move -- it'll move it some. But again, volumes between now and then are going to be flattish and then you'll see a little uptick. And if thing don't -- depending on completions at the end of the year, you could possibly see a minor decline post Bear Creek.

Okay. Thank you.

And we will go next to Shneur Gershuni with UBS.

Hi, good morning, guys. Most of my questions have been asked and answered several times, but I just wanted to just clarify a couple of things and I think you've sort of answered it with Becca's question before. But the results this quarter with respect to volumes, was that what you expected the first quarter to be, is it better or worse? Does it sort of change because you didn't change your guidance, does that mean that you still think that you're within your guidance or are you more towards the upper end now versus the lower end? I was just wondering if you can sort of give us some color as to 1Q performance relative to your official plan.

Yes, we came in pretty much as expected. I mean, as you would expect, you got some areas that performed a little better than expected and others that weren't quite as good. But overall, this first quarter performance is not a surprise to us and it's certainly consistent with our guidance we provided for the year. Just a bit more specific, in the Williston Basin, we continue to perform extremely well. In the Mid-Continent, we've not performed quite as well but when you look at it on the overall basis, particularly for a G&P segment, we are right on plan, right on our guidance.

Okay, perfect. A couple more follow-ups. You stated in the past, I think I saw it written as well too, that OKE stands in support of OKS. Do you expect to have to execute on that this year, or it's just more of a statement at this point in case if needed? Maybe you can sort of discuss that in context with any discussions you've had with rating agencies recently and so forth.

Shneur, this is Derek. The OKE cash balances there, really just is a prudency matter. We like having that flexibility. But as we've stated before, we don't have any plans really to issue equity at this point. So we'll continue to watch it, but no plans at this point. And in terms of rating agencies, I mentioned in my remarks certainly at the partnership we're committed to the investment-grade credit rating and that allows us some additional comfort should things not turn out exactly the way we would expect.

Okay. And then one last question just technical in nature, Roadrunner, what's the expected ramp this year?

I'll turn that question over to Phil.

Could you -- did you say ramp?

Yes.

Okay. Yes, it's first phase is in service as of March, so it is flowing 170 million a day. Second phase is due in service in the second quarter of '17 and that will ramp up to 570. And then third quarter will follow in 2019 and that's another 70 million a day. So total 640 million a day.

Okay, perfect. All right. Thank you very much guys.

You bet. Thank you.

And we will go next to Jeremy Tonet with JPMorgan.

Good morning.

Good morning Jeremy.

I was just wondering for the NGL gathering, if you could help us think through kind of what leads to the cadence of the ramp over the year. Is that kind of new plants ramping up or is it more on the connection side, or is it more ethane recovery or if you could just help us with that a little bit, that will be great.

Sheridan.

I think to know that coming out of the first quarter, we always see a little bit of a downturn on our existing plant because of the seasonality in the first quarter. So we ramp up through the year, some of it will be that. But most of it will be from the ramping up of the plants that we connected last year and the new plants that we're connecting this year. We really don't expect any incremental -- any substantial incremental increase in ethane recovery in 2016 in our guidance numbers. So mainly, it's going to be from new plant connections.

Okay. That's great. That's it for me. Thank you.

Thanks, Jeremy.

[Operator Instructions] We will go next to John Edwards with Credit Suisse.

Yes, good morning everybody. Just I wanted to kind of come back to the incremental ethane opportunity little bit, is the basic cadence of realizing the $200 million, is it more or less in line with what you've laid out on your slide eight of the deck you provided with the release where you're showing the expected incremental petrochemical ethane demand? Or is it going to be some other trajectory? Is it more kind of rateably each year the next few years? Help me understand that a little bit better.

John this is Sheridan. I think the best way to explain it is currently today we supply about a third of the ethane demand in the United States. And as you see that demand increase, as you see on page eight, I think that ratio will stay the same. So of that increased demand, we'll be able to see about a third of it on our system.

Okay. So is it proportionate then to the timing that you've laid out there or is it some other pace?

No, I think it's about proportionate to that timing.

Okay. That's really helpful. And then as far as you had made some reference to the potential for improvement to optimization margins, I think your guidance is $0.02. I mean what are the prospects you think for that number actually improving this year and perhaps next year?

Well, I think the spread between Conway and Belvieu will be -- move around quite a bit this year, but I don't think we'll see any material substantial increase in that spread until you see the ethane come online which will fill up the pipes between Conway and Belvieu and give you an opportunity for wider spread. So probably more better opportunity in '17.

Okay, great. My other questions have been answered. Thank you.

Okay. Ladies and gentlemen, that concludes today's question and answer session and also concludes today's conference. We'd like to thank everyone for their participation. You may now disconnect.