歐尼克 (OKE) 2016 Q2 法說會逐字稿

Good day and welcome to the ONEOK and ONEOK Partners second-quarter 2016 earnings call.

Today's conference is being recorded.

At this time I would like to turn the conference over to Mr. TD Eureste. Please go ahead, sir.

Thank you and welcome to ONEOK and ONEOK Partners second-quarter 2016 earnings conference call. A reminder that statements made during this call that might include ONEOK and 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 of 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?

Think you TD. Good morning and thank you for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners.

On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, Senior Vice President and Chief Financial Officer; and Senior Vice Presidents Wes Christensen, Operations; Sheridan Swords, Natural Gas Liquids; Kevin Burdick, Natural Gas Gathering and Processing; and Phil May, Natural Gas Pipelines. Before I hand the call over to Derek for the financial review, I will open with a few remarks and after Derek's comments I will discuss the segment's performance and have some closing comments.

We continue to like the progress we have made in the first half of the year towards achieving our 2016 financial goals at ONEOK and ONEOK Partners. Our geographically diverse assets, located in the Williston, Mid-Continent, Permian and Gulf Coast, are meeting our customers' needs by enhancing both supply and market connectivity. The asset footprint we have developed over the last decade has generated significant value to our stakeholders.

To put the scale of investment and return to our stakeholders into a little perspective, since 2006 we have spent more than $9 billion in growth capital projects and acquisitions. In 2006, ONEOK Partners adjusted EBITDA was $615 million and distributions declared in 2006 were $1.80 per unit, split-adjusted. The Partnership's 2016 adjusted EBITDA guidance is $1.88 billion and we expect distributions declared of $3.16 per unit in 2016.

This impressive earnings growth at the Partnership has also benefited ONEOK. In 2006, distributions declared for ONEOK's limited and general partner interest in ONEOK Partners totaled approximately $145 million compared with ONEOK's 2016 guidance of approximately $790 million in distributions declared from the partnership.

I would add we have prudently managed ONEOK and ONEOK Partners dividends and distributions through a number of challenging industry events without a decrease. We have slowed the capital spending during uncertain times to protect the Partnership's balance sheet and investment-grade credit rating while aligning our business to take advantage of growth opportunities.

Many of the investments we have made have positioned ONEOK Partners with continued running room for growth with minimal capital requirements. Available capacity in our natural gas liquids segments allows us to continue to benefit from increased volumes driven by expected higher ethane recovery levels and NGL volume growth from more than 180 natural gas processing plants connected to our system.

Our natural gas gathering and processing segment also has considerable available processing capacity as our new processing plants have demonstrated operating performance at higher capacity levels than our original design expectations. In addition, many of our gathering and processing plants are interconnected with each other, providing flexibility to direct NGL rich natural gas volumes to the most efficient plants.

Our hard-working and experienced operating team will continue to optimize our assets to further enhance performance across our facilities. As we continue to take advantage of the considerable capacity we have available across our natural gas and natural gas liquids businesses, our returns on invested capital, coverage and leverage metrics should continue to improve.

Now Derek will provide a brief financial update on the quarter. Derek?

Thank you, Terry.

Starting at the Partnership, second-quarter 2016 adjusted EBITDA increased 3% from the first quarter 2016, resulting from increased natural gas liquids volumes gathered and fractionated and higher fee rate higher average free rates in the gathering and processing segments. Even in this lower commodity price environment, the Partnership's year-to-date adjusted EBITDA of $900 million is nearly $200 million more than in the same period in 2015. Last year's earnings were weighted more to the second half of the year, but to Terry's points, our assets continue to produce solid earnings in a very challenging pricing environment and we have significant room to increase earnings with available system capacity.

Our distribution coverage ratio increased to 1.15 times in the second quarter and 1.11 times year to date. This includes a one-time benefit from a change in the timing of cash distributions received from the Partnership's equity method investment in Northern Border Pipeline. Beginning in the second quarter, cash distributions related to the Partnership's 50% interest in the pipeline are received monthly instead of quarterly. This one-time $15 million cash increased to distributable cash flow were approximately.07 times to coverage.

Excluding this benefit, our distribution coverage ratio still continued to improve. The second quarter 2016 represents the fifth quarter of consecutive increases in distribution coverage with our third consecutive quarter above 1.0 times. We continued deleveraging the Partnership's already strong balance sheet, as trailing 12 months GAAP debt to EBITDA improved again to 4.4 times at June 30.

We continue to expect leverage of 4.2 times or less for the full year 2016. The Partnership has ample liquidity, with more than $1.8 billion of capacity on its $2.4 billion credit facility. On a standalone basis, ONEOK ended the first quarter with nearly $180 million of cash and expects to have approximately $250 million of cash by year end 2016 with an undrawn $300 million credit facility, allowing us continued financial flexibility. ONEOK's second-quarter dividend coverage increased to 1.33 times with free cash flow of over $40 million after dividends.

Finally, you'll note a 7% increase in operating costs compared with the first quarter of 2016. This increase is mainly in the natural gas liquids segment due to the timing of planned asset integrity projects at our pipelines and fractionators and higher property tax estimates. I would like to reiterate from a financial perspective we're pleased with the progress we've made in the first half of the year. We continue to have no debt or equity capital market needs, including through our at-the-market equity program until well into 2017, although we continue to evaluate opportunities to proactively manage debt maturities and liquidity at the Partnership.

Lastly, I'd like to point out we accelerated the expected completion of phase 2 of the Roadrunner project in the WesTex expansion project to the fourth quarter 2016 from the first quarter 2017. With all things being equal, we could see a 2% or 3% resulting increase in the natural gas pipeline segment's operating income and equity earnings. We are maintaining our 2016 financial guidance expectations for both ONEOK and ONEOK Partners, and expect to continue to navigate the remainder of the year with prudent financial decision making.

I will hand the call back over to Terry.

Thank you, Derek.

Let's take a closer look at each of our business segments. Our natural gas liquids segment continues to be a key driver of fee-based growth for the Partnership. We recorded NGL gathered and fractionated volume growth across the segment's footprint, driven by recently connected natural gas processing plants and increased ethane recovery in the Mid-Continent. The ethane opportunity remains a strong expected tailwind for ONEOK Partners.

Our processing plant customers connected system average proximately 150,000 barrels per day of ethane rejection in the second quarter, down from approximately 175,000 barrels per day in the first quarter of 2016. However, a portion of the fees associated with the increased volumes were previously being earned under contracts with minimal volume obligations. We expect ethane recovery levels to continue to fluctuate for the remainder of 2016. We continue to expect a meaningful impact from the ethane opportunity beginning in early 2017 and expect $200 million in annual impact to the segment once in full ethane recovery.

In addition to the ethane opportunity, the growing STACK and SCOOP plays in Oklahoma present an opportunity for natural gas liquids volume growth as we remain a critical NGL takeaway provider in the area. Based on the conversations we've had with producer customers in the STACK and SCOOP plays and with the results they are seeing, we expect to gather an incremental 100,000 barrels per day of natural gas liquids from the play. Our current gathering system capacity can handle the natural gas liquids out of the Mid-Continent when the region is in full ethane recovery and we expect to have available gathering capacity of approximately 40,000 barrels per day at full ethane recovery.

We can expand by additional 60,000 barrels per day with capital expenditures of less than $100 million for a total available gathering capacity of more than 100,000 barrels per day. Excluding the impact of changes in ethane recovery, 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, included the connection of three third-party processing plants through the first half of 2016. We expect to connect two additional third-party plants, one each in the Williston and Mid-Continent and our Bear Creek plant in August 2016, which equals a total of six plant connections in 2016.

From a natural gas liquids perspective, supply and market connectivity remains our competitive advantage. Or said another way, our competitive advantages is our ability to connect our producers in key basins to consumers in key market centers. A very important component of our integrated NGL system is the connectivity we have between Conway and Mont Belvieu. We have a significant amount of available capacity between these two market centers, which allow the natural gas liquids out of the Williston, Rockies and the Mid-Continent to have connectivity to end markets.

In the natural gas gathering and processing segment, the average fee rate increased to $0.76 in the second quarter 2016, driven by benefits from increased volumes on previously restructured contracts and continued contract restructuring efforts. This average fee rate is an $0.08, or 12%, increase compared with the first quarter of 2016, and a $0.37, or 95%, increase compared with the second quarter of 2015.

We expect the average fee rate to continue to increase, but at a slower rate compared with the last two quarters. We are continuing to work on restructuring more contracts to be primarily fee-based to reduce earnings volatility and enhanced margins. Additionally we did add nearly 85 new well connections in the Williston Basin during the second quarter. There are 19 rigs currently on our dedicated acreage along with approximately 350 drilled, but uncompleted, wells in inventory.

Segment volumes decreased slightly compared with the first quarter 2016, impacted by planned facility maintenance and weather events in the Williston Basin. We estimate without these occurrences, the Williston natural gas gathered and processed volumes would have equaled the first quarter. The Mid-Continent's volumes were impacted by the timing of well completions and volume declines. I would like to emphasize that the gathering and processing segment's EBITDA increased approximately $10 million from the first quarter, even with lowered gathered and processed volumes, which shows the value of the enhanced margins achieved through our contract restructuring effort.

The STACK and SCOOP plays are also benefiting the gathering and processing segment as we continue to see strong producer results in the plays. The majority of the well completions we expect to see at the end of 2016 and early 2017 are in the STACK, which is becoming one of the top return plays, which bring significant opportunities to all three ONEOK segments and especially the natural gas liquids segment.

Our natural gas pipeline segment had another solid quarter. We moved up the expected completion of phase 2 of the Roadrunner Pipeline project to the fourth quarter 2016. The early expected completion resulted from good weather, limited issues with right of way and less rock than expected during the construction process.

We also moved up the completion date of the WesTex expansion project, as I mentioned previously, which is complementary to Roadrunner. This project is another example of our commitment to grow the Partnership's long-term fee-based business. Our continued focus on stable, fee-based earnings growth has positioned us well for the remainder of 2016. While we're optimistic about the long-term outlook for commodity prices, we'll continue to prudently manage our business and position it for continued earnings growth while weathering the sometimes challenging and cyclical nature of the industry.

Thank you for your continued support of ONEOK and ONEOK Partners, and as always, thank you to our employees, whose hard work, experience and good decision-making has made for another solid quarter amid difficult industry conditions. It is through our employees' hard work, creativity and dedication that our Company remains well-positioned to take advantage of the many opportunities we have under development.

Operator, we're now ready for questions.

(Operator Instructions)

Shneur Gershuni, UBS.

Just a quick operational question than a big picture question. You had some interesting the color about the Bakken. Had the weather issues not been there you would've been in line with the first quarter. When we think about the guidance that you'd sort of said at the beginning of the year, how would you say volumes are tracking versus plan? When we think about a few rigs being added into the basin increasing completion crews, I think was announced by Whiting the other day as well to, how should we be thinking about the exit rate for the Bakken? Do you think it'll be higher than what you were joined planning on in your original budget? In contrast, if you can talk about I guess a little bit more depth about producer completion plans in the Mid-Continent, does that change our exit rate there as well, to0? I was just wondering if you can give us little bit more color around that.

Sure, this is Kevin. If we talk about the Williston first, I think the volumes are progressing very much as we anticipated coming into the year. We have had some producers announce bring some -- bringing some crews back and we do have that factored in. The weather and the facility maintenance, we saw basically just a minor decline in the second quarter. We're kind of flat right now as we move in. We've got Bear Creek which we now say will be completed in August so we will see an extra 30 to 40 million cubic feet per day (MMcf) a day coming in when that plant comes online. Then towards the back half of the year we're looking flat -- flattish type volumes as we go through the end of 2016 with the completion activity and the rigs that we currently have kind of on the schedule.

If we transition to the Mid-Continent, a little bit different story. We absolutely expect a back-half weighting especially towards the end of the year as some of the large pads, the completions were delayed to the fourth quarter. From that standpoint, we do expect a ramp there but -- and we've also had some gathered-only volumes that have dropped off a little more than we anticipated coming into the year, but that's kind of how we see the Mid-Continent volumes shaping up through the end of the year.

This is Terry. Kevin, fair to say we are seeing a lot of activity in the STACK, in the STACK play and the feedback that we are getting from producers has been really remarkable. If you've got any other comments you have to say about discussions you're having with producers?

Again, the information I've seen come out so far this quarter and conversations we're having with our producers, the type curves continue to improve. There have been a couple announcements already that producers have strengthened type curves in the area. We've seen results that are been quite impressive and a lot of the analysts are now talking. It's one of the top plays in the basin. We have about 200,000 acres of dedication in the STACK so we're very positive and bullish on what we expect through the -- especially in the fourth quarter. It's just getting these completions on these pads done, most likely in the fourth quarter.

I guess a bigger picture question. When I looked at your one of your opening slides. I think it was slide 4. You sort of highlight the $9 billion of capital that you spent. When I think about it in contrast with the OKS guide of just under $1.9 billion in the EBITDA for this year, you've talked about $200 million worth of upside with respect to ethane in the near future, taking us over $2 billion. I guess it's not really a guidance question per se but in a more constructive commodity environment, I'm not talking peak oil, but a constructive environment, how much operating leverage does all this capital represent? Could EBITDA be another 10%, 20% higher in a more normalized commodity environment? Wondering if you can sort of give us a little bit of color about your operating leverage.

Sure. As we think about that operator leverage and the capacity that we have available, when we think about our business, the capacity that we have available are certainly in the most active basins, not just from a G&P perspective but also from an NGL perspective where we have capacity, are in the good spots, candidly. When you think about more constructive environment, say maybe $55 to $65 a barrel oil environment, we're well-positioned to capture more opportunities. If you think about the impact from an EBITDA perspective or the incremental EBITDA, I think a 10% to 20% improvement, if all those things happen, I think that would actually be conservative. I think we could outperform that considerably.

Great. Thank you very much, guys. I'll jump back in the queue.

Eric Genco, Citi.

I just wanted to touch real quick in the NGL segment. I was hoping you could expand a little bit about the MVCs that were absorbed by the increased ethane volumes. I didn't realize the MVCs were a significant piece of the system so I'm just wondering if you can tell me what parts of the system had the MVCs asserted with it? Are they escalating? Just want to make sure that, that doesn't impact in anyway the $200 million benefit that you had talked to in terms of it going to full ethane recovery.

Eric, this is Sheridan. When we looked at the $200 million uplift from ethane recovery, we took into consideration the MVCs but also the decrease in MVCs that you saw in the second quarter was not just from ethane, it was also from an increase in the C3-plus volume we were getting from the added plants that were coming online. It's not apples and apples when you compare that going forward. The big thing is the $200 million took into account what we have in MVCs that is already being captured.

What part of the system to you have the MVCs on?

We really have some across the whole system, but most of it is probably in the Mid-Continent.

Okay. I think also the press release you referenced that there was some benefit in the Bakken from increased ethane recoveries. I didn't necessary think the crack was wide enough to warrant a lot of Bakken (inaudible). Did I read that correctly or what's going on there? Is there some sort of discounting to be competitive there? Just wondering if you can give your thoughts there.

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

Okay. Thank you very much.

Christine Cho, Barclays.

I wanted to start on your STACK/ SCOOP comments. Terry, I think you said you have the opportunity to gather 1,000 MMBtu per day. What's the timeframe on this? I notice that you didn't say processing either. Is it just a gather-only contract? Also, if you could you just reiterate your comments about how you already have capacity to handle those volumes?

Okay, Christine. First thing, the number was 100,000 barrels per day and yes, we're talking primarily about gathering system capacity. That is NGL gathering system capacity when we make that comment.

Okay.

Sheridan, anything else you can share?

In terms of fractionations, we definitely think the first 40,000 barrels day we would have fractionation capacity for it. When we expand the next 60,000, we think there's capacity in Mont Belvieu with other fractionators to handle that. If it warrants, we would be more willing to build our fractionation capacity expand for that as we go forward.

Okay, great. I thought the first-quarter fee-based rate in G&P was the run rates go off of. I think that was what you kind of guided us towards last quarter. What happened in second quarter that drove this rate higher? I notice that your implied equity volumes didn't look like it got smaller, so any clarification would be helpful.

Kevin?

Christine, this is Kevin. Yes, when we talked about the first quarter we did say that we expected -- we were the most part thought we'd seen the peak of the increases. We did see some, again, some improvement in the fee rate. That's primarily driven from just the mix of where the volumes are coming. Each quarter volumes will have -- will grow in some areas, decline in other areas and just depending on the types of contracts, those volumes are growing or declining, will move that fee rate around.

In this case, we had additional volumes show up on our contracts that had been previously restructured that had higher fee rate and some of the declining volumes were occurring on the contracts that had lower fee rates. In addition, we continue to just as part of our normal commercial activities as contracts come up for term and so forth, we work with our producers to again try to remove as much risk out of our business as possible and convert, continue to convert and move the contracts to more fee-based contracts.

I see. On the restructurings, are they still mostly happening in the Bakken? How much of the Bakken can still be restructured, meaning what percentage of the volumes haven't been converted yet?

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

Christine, I guess -- this is Terry. I would add when we set out in the Williston Basin with this objective to restructure these contracts, there were some fairly large contracts that were already heavily fee-based that we felt like we could -- and we did, we left those contracts alone. We were satisfied with those, so those contracts still remain. I think for the most part I think we have accomplished what we set out to do. I would not anticipate a whole lot more contract renegotiation happening, obviously, until now some of these contracts up for term many years down the road. I think for the most part we've accomplished what we set out to do.

From ongoing perspective, we will stay focused in particular in the Mid-Continent to restructure where we can, understanding that the challenge there is that the contracts are much smaller. There's not a lot of large volume contracts and it's a bit more tedious work and of course more challenging. A more challenging environment, period.

Okay, thank you. Last question from me. How much MVC are you still collecting right now in the NGL business, dollar-wise or volumes? Whatever you can give would be helpful.

Christine, we've not disclosed that information and not going to disclose it here.

Okay, great. Thank you.

Tom Abrams, Morgan Stanley.

Just thinking about Oklahoman SCOOP/STACK and the excitement building there. Is any buzz that we get out of the Cana-Woodford, is that additive to the SCOOP/STACK thought process or is it just operationally separate?

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

Okay, fair. With all that verging excitement it's going to move up the need for some residual gas takeaway. When does the industry need to commit to a project? When can we -- would it be Roadrunner 3? How would you guys play?

I am going to let Philip May handle this question.

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

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

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

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

All right, thanks.

Danilo Juvane, BMO Capital Markets.

As an extension of the question on leverage, you guys have met your budget for the year thus far. If you continue to do so, what our expectations for the resumption of dividend growth and distribution growth at OK and OKS? How much is your leverage target sort of playing that decision?

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

As a follow-up to that, if we approach the end of the year and you are still targeting if not modest exceeding your budget, would that put you in position to consider an increase at that point? I guess what else would you be looking for at the end of the year?

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

Great. Thank you.

John Edwards, Credit Suisse.

Good morning and congrats on a nice quarter. Terry, you made some comments about ethane recoveries. I think you said it was 3,000 barrels a day so not a whole lot here in the first and second quarter but as we're moving here into the second half, in terms of incremental ethane recovery volumes, what do you think you're going to be seeing at this point? Obviously, you've put some slides out there where you're expecting a pretty large increase in 2017, so maybe if you can just -- a little more color on the trajectory would be great.

Sure. I'll let Sheridan tackle that question.

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

Okay. All right. So somewhere in the 80,000, 90,000 range of additional recoveries is, I guess is a fair number?

Yes.

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

I think directionally we would expect it to creep up, but again I don't expect that you're going to see the sizable increases we've seen over the previous couple of quarters.

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

Jeremy Tonet, JPMorgan.

This is Chris on for Jeremy. The first question's on G&P fee-based margins. (Inaudible) in the first half of this year so when we're thinking about the second half, I guess to what degree could contract restructuring benefit the second half of the year? Then also, how much of the mix shift could impact results in the second half as well?

As we've talked about, we've seen the uptick in the first half. As we think about the second half of the year, I would think about it kind of where were at to just a slight increase maybe as we go through the rest of the year.

In terms of the contract restructurings thus far, what inning would you say we are in, in terms of the existing or your current expectations? Also, in terms of your efforts thus far, what's been your success rate with customers and general feedback at large?

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

Great. Moving on to ethane recovery, you guys mentioned across your system you're seeing some increase ethane recovery but at the same time, that's kind of been offset by those MVCs, so I was wondering, what part of the system exactly? Is that on the fractionation or the NGL pipes? Any color there would be helpful.

Most of the ethane recovery we've seen the second quarter has come out of our Mid-Continent volume. Some of it has been on a transportation only and some of it you've seen come out in the fracs space. As a just a little bit ago, we -- today that ethane has gone back into rejection so we're back to where we were at the start of the year, between 175,000 and 200,000 barrels a day on the system.

When we think about the cadence going into 2017, I guess to what extent are these MVCs going to impact potential uplift?

The $200 million, when we said we had $200 million uplift when all of this ethane comes out, we took into account the MVCs when we stated that number.

Got it, that's helpful. Last one for me, on the Roadrunner, you guys are ahead of schedule there for 4Q 2016. I guess what time the earlier than expected startup date?

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

Thanks a lot, guys.

Craig Shere, Tuohy Brothers.

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

Well what I would say is we think that we will ramp up the Mid-Continent volume that goes to Belvieu in the first half of 2017 more weighted toward the later part of the first half and then the second half is where you get a little bit more the Mid-Continent. Maybe it would have some Conway pricing out of it. You would say you would see most of it weighted towards the second half but you will start seeing meaningful impact in the first half of 2017.

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

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

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

Broadly speaking, the low-hanging fruit in terms of cost containment or cost reduction opportunities is really attributable to reduce contractor costs. That is, the market and the rates associate with the services that we hire out have reduced dramatically and they continue to soften. That's probably the lion's share of the cost benefits. Certainly we're working to try and operate our assets more efficiently and find ways to reduce our maintenance costs and other ways than just the market and we've had some success at doing that. I think in the first quarter, I think generally speaking we were talking more on the order of what's the market given us in terms of reduced rates.

Okay. Do you see any ongoing opportunity there or would we have already kind of --

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

Okay, great. Last question. I'm sorry, this is probably in the prepared comments, but what was the spot volumes in the quarter again?

For NGLs?

Yes.

I don't think we've provided that number but, Sheridan?

It's about 8,000 barrels.

Okay. Great. Thank you.

Chris Sighinolfi, Jefferies.

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

Well, I won't make any comments about the producer, but what I will say is that with nearly all of the producers we've dealt with, all have understood the story and the rationale. They understood why our contracts had certain provisions in them that allowed this to happen or allowed the renegotiation to happen. They understood the need. They understood the requirement that we continue to need to be incentivized to invest capital in these areas. I think all the producers got it. None of them liked it, but they understood the reality.

They certainly did not want us to pick up and invest capital elsewhere. They needed capital to continue to be invested. They needed the services in order to monetize their reserves and continue to produce their crude oil, candidly, in the Basin. They all understood the rationale and as I've said before, it was a long process, one that was carefully -- we were very careful in our discussions with the producers and patient and very open.

Okay. Thanks.

Did that help you?

It does, yes. We hadn't seen an issue like that and then we saw this one last quarter, so I was just curious if that signaled a shift. It seems like it maybe was just a one-off situation. I appreciate the clarification on that.

Switching gears a little bit, maybe a question for Sheridan but wondering in your ethane outlook how much switching that you guys are assuming occurs by the crackers. I think earlier in the Q&A dialogue, you talked about beginning to move more ethane toward the first half of 2017. I'm just wondering what is baked in there with regard to effectively the feed stock substitute availability of the cracking fleet, if there was an assumption or if there is just a general way to think about that.

When you say switching I'm assume switching feeds to propane?

Yes, exactly.

Cracking propane instead of ethane? Our view always has been and we still understand these most of these crackers only can crack ethane, okay? There's few that have the capability to switch. I think there's been perhaps some, I don't know if it's confusion or what you'd -- the information hasn't been real clear. We talk to these petrochemical companies all the time and we have a very good understanding of what they can and can't do. Sheridan, you can -- actually I will let Sheridan.

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

Right. So switching that we'd be focused on would obviously be on the legacy fleet but if there's a pickup in ethane demand from the new and services, if prices are warranted not a totally crazy scenario to think that there might be some loss on the legacy fleet?

Right.

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

Right.

Okay. Thanks a lot, guys. Appreciate the color.

(Operator Instructions)

Michael Blum, Wells Fargo.

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

Sheridan, you got any sauce?

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

Thank you.

[Parisa Ozit], Simmons and Company.

Just a quick follow-up on the NGL supply opportunities in the SCOOP and STACK. When you're talking about the 100,000 incremental barrels per day of NGLs, can you just give us a sense of what kind of horizon assumptions are baked into this and whether (technical difficulty)?

I'm sorry, on pricing assumptions for the NGLs of what we would charge, only thing we have put out there is that the average price we have in the Mid-Continent's roughly around $0.08 per gallon. That is a combination of both when we deliver to Conway and to Belvieu. Most of these will probably go to Belvieu so you are probably $0.08-plus per gallon of what we would charge for this movement if our customers want to go to Belvieu.

Okay. Great. One other one on the continued strength in process and fractioning of volumes. Should we expect this to continue into Q3 or just expect more of the seasonal shift in Q4 as usual? Also, would you think of adding even more incremental processing plants aside from the three connections expected in the second half of 2016 if we continue to see this increase in volume?

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

Okay. Great. That's it for me. Thanks a lot. I appreciate it.

Tom Abrams, Morgan Stanley.

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

Kevin?

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

I got you.

Kevin, only thing I would add to that is in the core those gas-to-oil ratios are much higher than in other parts of the basin, right?

That's correct.

Thanks a lot.

That concludes today's question-and-answer session. I will turn the conference back to Mr. TD Eureste at this time for any additional or closing remarks.

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

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