Oneok Inc (OKE) — Q1 2016 Earnings Call Transcript

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 these 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 fundamentals 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 a $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 an 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 has resulted in ample liquidity, two 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 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 the 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 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 favorably 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 commitments 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 centers 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 focused 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.

Good morning. I have a couple of follow-up questions about ethane. I wanted to clarify something. You mentioned this, but regarding the increase in ethane opportunity from 150,000 to 180,000 barrels a day last quarter to 175,000 to 200,000 barrels a day in 2016, is this primarily due to third-party plants and a transition towards more liquid-rich drilling over time?

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.

I am curious about the ethane recoveries that are expected to come from the Bakken eventually. I understand the bundled costs and their economic implications, and you've mentioned that Bakken would theoretically be one of the last basins to be affected. However, I'm also interested in your comments about some of your services being non-discretionary. Ethane economics alone isn’t likely to drive drilling in the Bakken. Is there a way to analyze the pipeline stacks in the Bakken and how, as operations resume, ethane recovery might influence your business? Can we quantify this, or will we have to wait to see how it unfolds?

Eric, when we consider the ethane we transport, we haven't encountered significant quality issues on a large scale. Occasionally, there may be specific challenges based on the location of the pipes in relation to the end-users, but I don't foresee quality specifications significantly influencing ethane production from the Bakken or elsewhere. Regarding our non-discretionary services, producers need to process gas and extract liquids to meet quality standards. Ethane is an NGL that can be seamlessly integrated into the gas stream and diluted without major issues, unless there are industrial or commercial customers nearby the processing facility. Does that clarify things for you?

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

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 comes up mid-year, maybe some Mid-Con things. But if I remember correctly, there was a pretty healthy chunk of the Williston that 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 will make a few general remarks before handing it over to Kevin. In terms of our contract restructuring efforts, we have completed the majority of the contracts we aimed to address in the Williston Basin. Therefore, we do not anticipate significant further changes in that area. While there is some ongoing work, it is unlikely to have a substantial impact. The Mid-Continent area remains a work in progress, as we have a much larger producer base and many more procedures involving smaller volumes. This adds complexity to the Mid-Continent compared to the Williston, mainly due to the high number of contracts involved. That's the overview. Kevin, do you have anything else to add?

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, our connections will come from a few sources. As rigs continue to operate in the basin and as wells are being drilled or completed, we’ll connect those. Additionally, there is a backlog of ducts on our acreage, and as we coordinate with producers and adjust schedules, we will connect those as well. Therefore, our connections for 2016 will come from a combination of both sources. We still anticipate being in the range of 250 to 350 total connections 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.

Good morning.

Good morning.

You guys are 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?

Regarding West Texas, I won’t comment on that for obvious reasons. However, in terms of our fee-based activities, we have significantly mitigated risks. We've successfully renegotiated contracts, leading to an increase in our rates across the board, not only in the NGL sector but particularly in gathering and processing. As we look ahead, we do not anticipate any decrease in rates.

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 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 NGLs 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 to 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 could make some sense for us, potentially higher. But certainly as we've driven the risk out of 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.

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 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 to 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 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.

And what's the average contract life?

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

Okay, great. Thank you.

Thank you.

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?

There are a couple of points to note. First, regarding our flaring, there are likely 30 to 40 million associated with Bear Creek. When we bring Bear Creek online, we anticipate that about half of that will be resolved as the plant starts operating. As for the remaining flaring, there will always be some level of it, but we have significant capacity from our field infrastructure and processing plants. Therefore, when new wells come online, I don't expect that they will significantly increase flaring levels. I believe that number will reduce considerably in the latter half of the year once Bear Creek is operational. Looking at the data over the past few months, it seems that some of the reporting on total statewide flaring has been conservative.

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 product 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. In terms of getting more ethane out of the Bakken for uplift there, we see the opportunity 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 favorable comments you had about favorable 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 '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.

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, we have new plants coming online. The Bear Creek plant will enhance our NGL gathering. There's another plant in the Mid-Continent that will soon start operations. Just yesterday, a new plant began delivering into the West Texas pipeline asset. We are making progress and expect to see growth from this point onward.

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

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

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

We experienced strong volumes from Williston, which pertains to the MMBtus and is a significant factor in our performance. The gas from Williston is much richer, which explains the results you are observing. Overall, we expect our volume profile in the Williston to remain relatively stable throughout the year, and that is the reason for what you're seeing.

But you're also adding Bear Creek in Q3?

Right, that will result in an increase of 40 million cubic feet per day. When considering the overall total, the change will be minimal; there will be some movement, but overall volumes are expected to remain stable until we see a slight increase. Depending on completions at the end of the year, there is a possibility of a small decline after Bear Creek.

Okay. Thank you.

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?

Could you clarify if you mentioned 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 the 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.

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.

Coming out of the first quarter, we typically observe a slight decline in our existing plant performance due to seasonal factors. As the year progresses, we'll see an increase, which will be partially attributed to this seasonality. Most of the growth, however, will come from the plants we brought online last year and the new plants we are connecting this year. We do not anticipate any significant increase in ethane recovery for 2016 within our guidance. Therefore, the main contributions will stem from the new plant connections.

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

Thanks, Jeremy.

Yes, good morning everybody. Just I wanted to kind of come back to the incremental ethane opportunity a 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 that 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?

I believe the spread between Conway and Belvieu will fluctuate this year, but I don't anticipate any significant increase in that spread until ethane comes online, which will fill the pipes between Conway and Belvieu and create a wider spread. Therefore, there will likely be better opportunities in 2017.

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