歐尼克 (OKE) 2016 Q3 法說會逐字稿

Good day, and welcome to the third-quarter 2016 ONEOK and ONEOK Partners 2016 earnings call. Today's conference is being recorded. And this time, I'd like to turn the conference over to Mr. TD Eureste. Please go ahead, sir.

Thank you, and welcome to ONEOK and ONEOK Partners' third-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 Act 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, TD. 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, 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 Phill May, Natural Gas Pipelines.

In yesterday's earnings releases, we reiterated that ONEOK and ONEOK Partners expect to finish 2016 in line with financial guidance. In addition we provided updated 2016 volume estimates for the gathering and processing, and natural gas liquids segments in the third-quarter earnings presentation.

As I have discussed previously, our industry is experiencing one of many down cycles in my career, and it has been particularly challenging, due to the duration of the low commodity price environment. While the cyclical nature of this industry continues, we are seeing more positive data points from our producer and end-user customers. Industry fundamentals seem to be improving, and most importantly, ONEOK Partners is well-positioned to benefit from growth opportunities in 2017 and beyond.

Our businesses have performed well in a tough environment, and we remain disciplined and committed to making prudent operational, commercial, and financial decisions. As I think about our opportunities I remain confident in our ability to serve our petrochemical customers as their ethane demand grows. We also continue to see producer activity ramping up in the STACK and SCOOP, which we expect will benefit all three of our business segments. And most importantly, the available capacity in our natural gas liquids and natural gas gathering and processing segments gives us room to grow, without the need for large capital spending.

Our more than $9 billion of investments over the last 10 years gives us the flexibility to grow with our producer and end-user customers, without needing to spend significant capital. The efforts we have taken during this downcycle to better position ONEOK and ONEOK Partners will allow us to continue providing value to our stakeholders.

Derek, that concludes my opening remarks.

Okay. Thanks, Terry.

Starting with the Partnership, third-quarter 2016 adjusted EBITDA increased 3% compared with the second quarter of 2016. And year to date adjusted EBITDA of approximately $1.4 billion represents a 23% increase compared with the same period last year, benefiting from recently-completed capital growth projects across our system, and sustained higher average fee rates in the natural gas gathering and processing segment.

ONEOK Partners' distribution coverage ratio was 1.11 times for both the third quarter and year to date 2016. In yesterday's earnings release, we also lowered the Partnership's expected maintenance capital spend for 2016. About $10 million of this reduction relates primarily to the timing of an NGL relocation project, $5 million for information technology upgrades, $5 million from lower-than-expected vendor and contractor costs, with the balance being various smaller items.

We continued deleveraging the Partnership's already strong balance sheet, as trailing 12-months GAAP debt to EBITDA improved again to 4.3 times at September 30. We continue to expect leverage of 4.2 times or less for the full year 2016. The partnership has ample liquidity, and more of than $1.7 billion of capacity on its $2.4 billion credit facility at September 30.

In October, we repaid $450 million 6.15% senior notes, with a combination of cash on hand and short-term borrowings. We continue to have no debt or equity capital market needs until well into 2017. However, we will continue to assess the markets for opportunities to proactively manage our future debt maturities and liquidity at the Partnership.

The proactive steps we have taken to improve our leverage position and balance sheet are being recognized. In October, Moody's affirmed the Partnership's investment grade BAA2 credit rating, and improved our outlook to stable from negative. Also, we expect these improvements will provide the Partnership flexibility, with excess coverage in the future. Options include repaying debt, funding capital expenditures, acquisitions, or increasing the distribution.

On a standalone basis, ONEOK ended the third quarter with more than $230 million of cash, and continues to expect 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 third-quarter dividend coverage was 1.3 times, consistent with the second quarter.

ONEOK's healthy coverage and liquidity provides flexibility as we transition into 2017. Leverage improvements, increased distribution coverage, and increased fee-based earnings at ONEOK Partners have decreased the potential need for ONEOK's support of the partnership.

We will continue to be a supportive general partner to ONEOK Partners, to help maintain its investment-grade credit ratings, but also recognize that we have many potential options for the excess coverage at ONEOK. Those options include purchasing additional units in the partnership, repaying debt, repurchasing ONEOK shares, funding ONEOK Partners' capital growth at the ONEOK level, acquisitions, and increasing dividends to shareholders.

I would like to reiterate, from a financial perspective we are pleased with the progress we have made in 2016 at ONEOK and ONEOK Partners. Through the downturn, we have maintained our $0.615 per quarter dividend at ONEOK, and our $0.79 per quarter distribution at ONEOK Partners, while also improving coverage and reducing leverage through the proactive steps we have taken.

And we continue looking for additional ways to increase shareholder value. I'll now turn the call back over to Terry.

Thank you, Derek. Let's take a closer look at each of our business segments. Let's start with our natural gas liquids segment, and some updates to our outlook for the year.

In the presentation we released yesterday with earnings, we updated our expected NGL volume estimates for 2016. We have seen lower volumes than expected with the lower margin gathered only barrels, particularly on our West Texas LPG system and in the Barnett Shale. However, we have also seen higher fractionated volumes, as gathered and fractionated barrels that earn higher fee rates have been strong on the Bakken NGL pipeline and the Mid-Continent region, and we have also fractionated more spot barrels during the year.

We expect 2016 gathered volumes to average approximately 780,000 barrels per day, compared with our previous expected range of 800,000 to 870,000 barrels per day. And we expect volumes fractionated to average approximately 590,000 barrels per day, which is at the high end of our previous expected range.

In the third quarter of 2016, we connected two additional third-party natural gas processing plants. One each in the Williston basin and Mid-Continent. Including the connection of our Bear Creek natural gas processing plant in the Williston basin, we have connected a total of six new plants to our NGL system in 2016.

At full capacity, Bear Creek is expected to generate approximately 10,000 to 12,000 barrels per day of wide grade takeaway, excluding ethane. The expected ethane growth from the petrochemical industry remains a key opportunity for ONEOK Partners.

As we have said previously, approximately one-third of the ethane currently being rejected in the US is on our system. We continue to expect a meaningful impact from the ethane opportunity, as new petrochemical plants come online, plus an increase in ethane exports during 2017. And we expect as much as a $200 million annual EBITDA impact to the segment, once in full ethane recovery.

Recently, we've been talking quite a bit about the STACK and SCOOP plays in Oklahoma, and the rapidly developing growth opportunities they can provide to all of our business segments, but particularly our natural gas liquids segment, because of our position as a critical NGL takeaway provider in the area.

We estimate that we are currently gathering approximately 150,000 to 200,000 barrels per day of NGLs from the STACK and SCOOP areas, which accounts for more than 20% of our expected 2016 gathered volumes, and demonstrates our strong position to growing STACK and SCOOP areas of the Mid-Continent, where many producers are moving in drilling rigs, and seeing very positive results. Wells in the STACK play, in particular are very NGL rich, with 6 to 9 gallons of NGLs per MCF in the natural gas stream.

Moving on to natural gas gathering and processing segment, we expect natural gas volumes gathered to average approximately 1.5 billion to 1.6 billion cubic feet per day in 2016, compared with the previous estimates of 1.7 billion to 1.8 billion cubic feet per day. The sole driver of these changes, as we have said previously, are delays to large multi-well drilling pads, and steeper than anticipated declines in gathered only volumes in the Mid-Continent. We expect natural gas volumes processed to average approximately 1.4 billion to 1.5 billion cubic feet per day in 2016, compared with previous estimates of 1.5 billion to 1.6 billion cubic feet per day.

Our 2016 Williston basin volume estimates remain unchanged, and have benefited from a backlog of drilled but uncompleted wells, flared natural gas capture, new plants placed in service, and continuing infrastructure build out. While Mid-Continent volumes have been volatile this year, we continue to expect the segments to have higher natural gas processed volumes in the fourth quarter, compared with the third quarter 2016, as we have seen the completion of several wells in October, and expect additional multi-well pad completions through the end of 2016, and into early 2017.

We expect Mid-Continent process volumes to reach nearly 690 million cubic feet per day in the fourth quarter. Specifically in the STACK, drilling economics remain viable, based on recent conversations with our producers, and well results have been impressive. We have seen some wells on our acreage average 30-day peak initial production rates of 8 million to 10 million cubic feet per day.

In Williston basin, we expect natural gas processed volumes to reach nearly 780 million cubic per day in the fourth quarter. This volume increase is driven by our recently completed Bear Creek plant, and by increased well completions, as producers work off some of their drilled but uncompleted well inventory. The segments average fee rate remains $0.76 per MMBTU in the third quarter of 2016, unchanged from the second quarter 2016, and up $0.33 per MMBTU, compared with the third-quarter 2015.

Sustained higher fee rates have provided stable earnings for the segment, and we expect the fee rate to stabilize in this range, with some fluctuation due to volume or contract mix changes. With the full benefit of our contract restructuring efforts being realized in 2016, and volume benefits from capital growth projects completed this year, we expect to finish 2016 in line with our financial guidance for the segment.

In the natural gas pipeline segment, adjusted EBITDA for the third quarter of 2016 increased 17% compared with the second quarter of 2016, driven by increased contracted capacity. In October, the segment completed its 260 million cubic feet per day WesTex transmission pipeline expansion, and the second phase of its joint venture Roadrunner gas transmission pipeline, which adds an additional 500 million cubic feet per day of capacity to the Roadrunner pipeline. Both projects were completed ahead of original schedules and below cost estimates, and are fully subscribed under long-term fee-based commitments.

We have been successful in our strategy to move markets such as Mexico closer to supply areas, such as West Texas and in the Mid-Continent. Our recently-completed Roadrunner and WesTex pipeline projects are examples of our ability to do this, and as the STACK and SCOOP continue to gain momentum, we are well positioned to provide needed residue takeaway options.

We are currently connected to 34 natural gas processing plants in Oklahoma, with a total combined capacity of approximately 1.8 billion cubic feet per day, and have a broad footprint throughout the state, placing us in a strong position to offer transportation and storage services, as producer activity picks up in the Mid-Continent. Related to this effort, yesterday, we posted a binding open season, soliciting interest in expanding segments of our Intrastate natural gas pipeline in Oklahoma, ONEOK gas transmission, to provide additional residue takeaway from the STACK and SCOOP production areas.

The expansion would provide increased capacity and delivery options into pipelines in Western Oklahoma, serving markets in the upper Midwest and Texas. We have secured a firm commitment from a customer to support expanding the pipeline by an incremental 100 million cubic feet per day, and in the open season, we will seek additional long-term firm commitments from shippers to support a broader expansion of the facility.

With nearly 100% fee-based earnings in the segment and our portfolio of high quality and high connectivity assets, we will continue to look for additional opportunities to grow this stable business. Acting as a solution provider to end-use markets has served us well, and will continue to be a key segment strategy.

To wrap up, I would like to reiterate that we expect to finish 2016 in line with our financial guidance. We have seen better than expected results so far in our natural gas pipeline segment, and on target results in our gathering and processing segment. Our natural gas liquids segment may end slightly below operating income in equity earnings guidance for the year. With line of sight into our expected earnings growth, strong balance sheets at ONEOK and ONEOK Partners, and continued healthy coverage, we expect to be in a position to increase dividend and distribution payments to stakeholders in the second half of 2017, if the industry's fundamentals continue to improve.

Financially and operationally, we are in a strong position, and we have the flexibility to take advantage of opportunities to create additional shareholder value. Thank you for your continued support of ONEOK and ONEOK Partners, and as always, thank you to our employees for your hard work and continued dedication to operating our assets safely and environmentally responsibly. Operator, we are now ready for questions.

(Operator Instructions)

Eric Genco, Citigroup.

I was wondering if we could talk about OKE's tax situation going into 2017? What are you expecting for the cash tax rate, if nothing changes? And how are you thinking about managing coverage going forward, if we have to assume that cash taxes were to go up?

Eric, this is Derek.

We will guide to cash taxes for 2017 when we roll out the rest of our guidance, maybe later this year or early next year. We do think about, and we do forecast cash taxes as we think about distributions. Obviously, we've been running thicker coverage at OKE here in this period of some uncertainty, but as we look forward and think about the dividend growth, we will consider the cash taxes as a part of that analysis.

Okay. And if you were to consider doing a transaction at the OKE level, are there ways that you could basically could a structure a deal where you would be able to take advantage of the OKE currency, but also shield some of the taxes? Like if you were to buy a C Corp that had some deferred tax assets, would you be able to use that to shield some of the OKE income, or does it exclusively go to whatever you purchase? How should we think about that?

I think you are thinking about that right, Eric. Certainly we have, with the two balance sheets, have some flexibility in terms of structuring any acquisition -- a stock-for-stock deal, as you know, probably would not result in a step-up in the basis, but if we structured a transaction in some other way, such that the acquired entity is stepped up for tax purposes, obviously that would generate a fair amount of additional shield there.

Certainly Eric, this is Terry. We are obviously highly focused on the tax liability at OKE, and we are continually thinking about opportunities where we can acquire assets or businesses that could help shelter those taxes. That is an ongoing process, and certainly as we prepared our 2017 -- we are in the middle of our 2017 planning process with our Board. As we come out of that process, we may be in a position to shed even more light on our thoughts. And I think, broadly speaking, as we think about OKE, to your earlier question, and we've kept this thicker coverage in this very challenging environment. But I think as you think about coverage going forward at OKE over a much longer term period, we're going to gravitate more toward a 1.0 to 1.1 coverage rate. That's how we're thinking about it on a much longer-term perspective.

Okay. Thank you for taking my question. I'll jump back in queue. Thank you.

Shneur Gershuni, UBS.

Maybe I can follow-up on the last question, actually, that you just had, which I think you answered based on the OKE level. I was wondering if we could talk about it at the OKS level. Can you share with us how Management and the Board is thinking about what is the acceptable coverage ratio that you would like to see at OKS, before you would consider an increase? Some other management teams have talked about 115 being the new 105, or 120 being the new 105. I was just wondering if you could your thoughts with respect to that? And how you are thinking about higher retained DCF to fund growth CapEx on a go-forward basis versus just maintaining the old 50-50 model?

Shneur, we are thinking very similar to our peers, carrying a bit thicker coverage. I think, broadly speaking, over the long term at OKS, coverage in the 1.1 to 1.2 range is how we are thinking about it longer-term.

Okay.

And if we can establish a sustainable coverage at that level, then certainly we have to be thinking about distribution growth, when we get to that point.

Right. Okay. So one 1.1 to 1.2 is the new target range that we should be thinking about for OKS?

Yes. That's fair.

And then, in terms of all the detail you gave on the SCOOP/STACK, I think it was on slide 4, talked about the potential for the SCOOP/STACK, you mentioned very minimal capital for 100,000 barrel increase on the NGL system. You also highlighted that you have some idle capacity that can come online. I guess I have two questions. One: given all the excitement by the producers, what is the timeframe that we would expect to see you FID that decision, to spend $100 million in capital, and bring that idle plant back? And then secondly, could we actually see newbuilds of facilities as well too, beyond the operating leverage that you just highlighted?

Well, Shneur, I think we are seeing tremendous development in the STACK and SCOOP, as we speak, and it is still early. Now, this 100,000 barrel a day potential, as we have said in the past, is a two- to three-year phenomenon. Certainly at the rate we are seeing this development, it could happen earlier. A two- to three-year time frame I think is an appropriate way to think about it. As we move into 2017 and we hear more about producers' plans and as they approve their budgets, we are going to get a better sense of the SCOOP and STACK and what it will mean to us from a timing standpoint. We will be in a position to better refine that, certainly, as we move into the first quarter of 2017.

Sheridan, do you have anything to?

The only thing I would add is that we continue to get multiple calls from the processors out there trying to add more plants in the area, and as processors are talking to us, they continue to revise their volumes up. So the chance of that moving forward in the two to three timeframe is a great possibility.

Okay. Great. Thank you very much. I really appreciate the color.

Brian Gamble, Simmons & Company.

I want to follow up on that point: lots of producers out this morning and last night chatting about SCOOP/STACK development, Devon, Marathon, Newfield, the whole nine yards. It seems like they are adding rigs and putting out wells that are well in excess of what they had previously planned. Does the 150,000 to 200,000 a day that you're talking about, that you are pulling now from SCOOP/STACK, is that -- where is the upside potential there, without additional assets on your end? And then, you have mentioned the 100,000 barrels a day and the minimal capital there. Is there additional capacity within the system as it sits today for Q4, Q1, maybe Q2, just short-term ramps? Or do we need to see dollars flow in that direction to allow additional volumes to get to the system?

Okay, so you answered the question. We do have capacity available today for some of that. I think -- what did we say, Sheridan? 40,000 barrels a day today? That is capacity that is existing naturally in the system, and we don't have to expend any meaningful capital for that. The incremental 60,000 barrels a day that gets you to the 100,000 is where we will have to spend some capital. I think that number was on the order of $100 million.

To get to the whole 100,000, we need to spend about $100 million, and the bulk of that is going to be the incremental pumps on Sterling II to get you the 60,000.

So the gathering infrastructure that we have in the play is pretty extensive, and it has been there a while. So we are well positioned. It is the downstream, moving the barrels downstream to the market, where Sheridan indicates where that capital has to be spent.

That's helpful.

And then on the nat gas numbers, pulling those down for the year, it seemed like the direction we were heading after the Q2 results and the softness that had been targeted for Q3, when we look at the exit rates, you mentioned the multi-pad well delays coming into the fold. Is that the only benefit that we are getting that leads to those higher rates? Or do those higher rates also foreshadow activity increases, on top of the delayed connections?

This is Kevin.

It's really both. We are seeing -- there have been the delays that have really caused the lower volumes and the lower guidance. Those pads are coming online. We've seen some of it already completed in October. There are now many additional wells to come online through the rest of this year, and we have also got visibility into early 2016, to expect that ramp to continue on into the early parts of 2016, as well. So with the producer activity, the ramp that we have seen in completions, and also some visibility we have into rigs going forward, that's what gives us the confidence that the ramp will continue through Q4 and into Q1.

Kevin, what type of magnitude of change could we see from Q4 into Q1, based on your visibility to date? I know it is too early to guide 2017, but just given those comments, how dramatic is that continued ramp from current plans that you guys are aware of?

Well, it is a little too early to talk about some specific numbers into Q1. And part of the reason there is, as Terry talked in his remarks, the size of these wells are extremely large, so pads or wells being completed and moving around a little bit can swing your numbers. But as we release our guidance for 17, we will provide some more color on how that ramp occurs throughout the year.

Great. I appreciate that, Kevin.

Christine Cho, Barclays Capital.

I actually wanted to start off on some of the M&A comments, or a response that you gave to an earlier question. When you talked about cash being paid to shield taxes versus giving equity to a potential target, what is the leverage that you would be willing to go to at the parent, in such a scenario?

Christine, this is Derek.

I think it depends a bit on the nature of the acquisition, and the assets or the businesses within that business. So if you think about what we have been trying to do over time is move more towards fee-based businesses, certainly the pipelines business, where we gotten Roadrunner now in service, and the WesTex expansion. Those more highly fee-based businesses perhaps could carry a little more leverage than one that is more volatile. I think it would depend a bit on that. What we have been targeting at the Partnership for leverage is 4 times or less, and we think we will be at 4.2 times or less by the end of this year. I don't think you would expect it to be dramatically higher than what we are thinking about today.

Christine, I think ideally for us, the objective is not get to 4, but to get below 4. That is really the long-term goal. To stay below 4.

At the LP?

That is right. That's in LP.

Okay. And then moving over to the NGL segment, your Bakken G&P volumes were down sequentially over last quarter, yet the volumes on the Bakken NGL pipe was up. It looked like that was some incremental ethane, but could you confirm that and talk about what's driving that?

Christine, this is Sheridan.

The ethane is about staying between the two quarters. We are seeing it, saw a little bit of ramp up in our other volumes from the third-party plant that makes up a little bit of the difference there.

Okay. I think historically you guys have talked about 25,000 barrels per day of ethane flowing down that pipe. What is it currently running at?

Actually about, I think what we said is 25,000 barrels a day is what ORM has extracted. What our plants have, we are seeing above 30,000 barrels a day, if you put all the plants in there.

That is affiliated and unaffiliated plants.

You get above 30,000 with the non-affiliated plants.

Okay, and we should continue that, that level continues going forward?

That is correct.

Okay. And then, I might be getting ahead of myself, but when we think -- you talk about Sterling III expansion and it's clearly really low-cost -- 100,000 barrels per day -- I mean 60,000 that you could add for $100 million. But is that the last of the low-hanging fruit? Because we do have line of sight into all of those assets being fully utilized. So beyond that, would it have to be looping, if you were to add capacity in? Does the capital spend become meaningful if you want to add capacity beyond that?

Christine, if you want to add more raw feed capacity between the Mid-Continent and the Gulf Coast, which would be expanding Sterling beyond the 60,000 or expanding Arbuckle, you will be talking about loops, and it will be more meaningful.

Okay. Can you give us an idea of how much more meaningful?

Well, a lot depends on how much volume you want to put on there, and which one we put it on. But I can't give you an idea without having run it through the hydraulics and everything else. And volume predictions.

What about newbuild? How much more expensive with that be versus the looping?

A newbuild would be substantially more expensive. If you think about putting pumps on, it's actually really low hanging fruit, very cheap, as we just said; you get 60,000 barrels a day for less than $100 million. And if you're going to go put in a line, depending on what size the line in, you are talking probably a little bit under $100 million -- I mean $1 million a mile to put that in. So looping is going to be much closer to putting pumps on than it will be to a completely newbuild.

Christine, the looping projects that we're talking about, we're not talking about necessarily a loop of the entire pipeline. These are strategic loops between pump stations that we put, depending upon the volumetric need, in the most efficient place. So we're not talking about looping the entire pipeline. So the capital expense, while greater than just putting in pumps, is not going to be the same as looping the entire pipeline.

Got it. Great. Thank you for the color.

Jeremy Tonet, JPMorgan.

I'm sorry if I missed it, but did you touch on the number of DUCs on your acreage across your system?

We have not touched on it but we will tell you the numbers about 375 or so in the Williston basin, on our dedicated acreage. Is that right, Kevin?

That's where we're maybe at, maybe slightly lower than that right now. That's where we do expect that number will start to trend down through the fourth quarter. That's what, as we talked about our Williston volumes and Terry in his remarks, when we think about the increased activity we are seeing, a lot of that is the completion of DUCs. So we will see that number trend down between now and the end of the year.

Thanks for that.

And then there has been a good amount of conversation on M&A in general. I was just wondering if you could take a step back at a higher level, and how you see the market right now as far as the bid-ask spread? There has been some consolidation. There has been some transactions recently in this space. How do you see ONEOK fitting into that? Any thoughts on that?

Jeremy, we continue to assess opportunities and the challenges continue to be to find opportunities or potential targets that are willing to transact. The bid-ask spread is still wide. I think there will be more transactions, and certainly for us, as we think about transactions, and not just from an M&A perspective but acquisitions, do they strategically make a lot of sense and is there a good fit? Do they make sense within our footprint? Do they bring an inordinate amount of commodity risk to us, or do they perhaps bring a lot of fee-based, stable fee-based business to us? Those are all things that we think about. And certainly our bias is more towards fee-based, and not as much commodity exposures as some of the midstream businesses have.

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

John Edwards, Credit Suisse.

You made the comment in the opening remarks on the potential raise in the distribution if things continue to go well, perhaps in the second half of 2017. Is a logical read-through there is, you expect your leverage at OKS to drop under 4 times by the second half of next year?

Yes, John. This is Derek.

We do expect levers to continue to ratchet down as we move through 2017. I would expect that we would be in that area.

Okay. And Derek, I presume before you contemplate recommending an increase with the distribution, you would really rather be below 4 times leverage, correct?

Well sure, John. We would. I don't think we draw bright lines here, and we are certainly looking forward, even beyond 2017, as we think about going back to increasing the distribution. If we have got good line of sight, I don't know we will draw a bright line, but as I mentioned, we continue to see that leverage ratchet down, and you have really seen that quarter after quarter here. I don't expect that to change.

Okay. Great. And then just following on Jeremy's question on the M&A front.

Obviously, you want to have businesses that could potentially integrate with your existing footprint, be fee-based. Are you looking at any step-out opportunities or something, where you think you would like to geographically be in areas where you are not currently? Any thoughts around that potential appetite?

Most of the potential targets that we think about do have some overlap within our existing footprint, but do modestly reach into some other areas. I think that could make sense for us. Looking at a collection of assets standalone, significantly outside our geographic footprint, just buying stuff because perhaps you can get it at a good value, certainly does not have much appeal to us. But modestly outside our footprint could make some sense.

Okay. My other questions have been answered. Thank you so much.

Michael Blum, Wells Fargo Securities.

Just one question, really.

Just on the quarter, can you talk a little bit more about what is driving lower volumes on West Texas LPG? I would think, just given the dynamics and the premium, that might be at least steady to growing. Does that have anything to do with the rate dispute that is going on?

Michael, I think most of that on West Texas line is ethane rejection. That is most of the impact. Sheridan, anything else here?

That's right. Especially from some of the newer plants we've added there.

Okay. Thank you very much.

Ethan Bellamy, Baird.

What does the remaining flared gas capture opportunity in North Dakota look like? How much of a backlog do you think you have there?

This is Kevin.

We are still in that 70 million to 80 million a day range. We have brought on Bear Creek. The state reports the flaring a couple months in arrears, so we don't have that data yet, to give the exact numbers. But I would absolutely -- we know the flaring has gone down as Bear Creek has ramped up. We just as recently as last weekend completed the last step of a gathering system expansion that put out some additional flares, so we are expecting that run rate maybe to be in the 5% range going forward, if you think about our total production and the gas capture we expect going forward.

Just to understand it correctly: 5% year on year versus 2015 total gathering up there?

I am not sure I followed you there.

What do you mean exactly by 5%?

Yes. 5% of the production. So if you go back to that theoretical chart that we had put out there, we are in that, a little over 800 million a day of production on our acreage. So if you look at 5% of that, 40 million to 50 million a day of flared gas may be ongoing.

As you look forward, when would you see that opportunity exhausted in terms of -- at some point, are you going to be capturing every new molecule that is produced? Are we going to see a consistent backlog there, as producers continue to bring on wells and flare gas?

I don't think it is ever going to go away completely. There is always going to be some level of flared gas just due to ongoing -- you are always tying in new infrastructure and new well connects. You are always going to have operational hiccups. So there is always going to be some level of flaring, and that is what I think that 5% range, that would be kind of an ongoing run rate.

Okay. That's helpful. Thank you very much.

(Operator Instructions)

Craig Shere, Tuohy Brothers.

Speaking of M&A, are you still confident about ultimately hitting that 6 to 8 times EBITDA multiple all-in for the West Texas LPG pipeline?

Craig, this is Sheridan.

Yes, we are still confident. We are out there actively engaged with a lot of potential new processing plants that are coming on. We are very excited about the volume growth that we see on the West Texas system. We are very confident about getting to the 6 to 8 times, by, I think what we said is 2020.

Okay. And any color on when that rate dispute might be resolved? You are below market on your rates, aren't you?

We are below market on the rates. I think the best thing we can say about this is that we're going through the process. We are comfortable about our case, but it is up to the Texas Railroad Commission how the case progresses. We hope it's soon.

Did they give a timeline for that?

No. We have a procedural schedule that we are walking through.

Understood. And on this new STACK residue gas pipeline opportunity, is it fair to say that, that ought to be a much better than normal gas pipe EBITDA multiple, and how large could it be?

This is Phill.

I think it would be probably a good multiple project. It is at this point, just expansion. There may be opportunities to develop more capacity as the open season matures, which may mean that we need to put in some pipe. But it is probably a 200 million to 400 million a day, I would say, is the sweet spot for us, and it provides a lot of interconnectivity with the interstate pipelines out in West Texas. It seems to be a very popular discussion, because of the value associated with getting the molecules out there.

Phill, you probably look from a multiples standpoint, probably at a low-end of that typical 5 to 7 times. You have a low end of that multiple, right?

Yes.

Great. Thank you.

That is great for a gas pipe.

Yes it is. Great project.

And there is some noise in the quarter -- some things are a little better than one would have expected, gas pipes had a good quarter. You had some down, some of the more volatile margin stuff, with spreads. But you basically met Street expectations. And you are guiding to flattish to up fourth-quarter NGL volumes and rising G&P volumes sequentially. Commodity pricing is much higher than the third quarter to date. ISO to normal butane spreads are up sequentially into the fourth quarter, and you'll get a fourth-quarter contribution from the recently completed pipes.

My question is, if you think Street expectations of just over $20 million higher sequential fourth-quarter EBITDA might be light?

Craig, from a Street expectation standpoint, what we have told you is that from a financial guidance perspective, we are going to hit our numbers. Okay? I don't know where that puts you in the fourth quarter relative to the Street, but we feel highly confident in our ability to hit this financial guidance.

You are right. There is a lot of noise in the business, and the industry, and there is a lot of things that move up and down. And I am really glad we are in a lot of basins and we have a lot of levers to pull, and we have pulled some levers during the third quarter, and we continue to pull levers each and every quarter. We have a lot of optionality, a lot of flexibility, a lot of opportunity. We do have some upside in the fourth-quarter. Some of these volumes in the G&P business materialize as these big pads come online. It has not gotten cold yet, so you could see some upside in terms of NGL pricing and spreads, and what have you. But you also do have headwinds too, and you have got heavy inventories in the industry that could weigh on it, and some uncertainty in the export markets that could affect the industry near-term. All in all, for us, it equates to a high degree of confidence in our ability to hit our numbers in terms of our guidance. Does that help you?

That does. And I apologize. I got on a little late. Had trouble dialing in. Was there any comment about the third quarter MidCon spot NGL gathered and the NGL frac spot volumes?

Sheridan?

The spot volumes in the third quarter were minimal. We didn't have a whole lot of spot volumes in the third quarter.

Okay. Great.

And lastly, with M&A, is there any particular side to the business that you would emphasize? Or a geography like the Permian where you already obviously made a move, or maybe the Niobrara? Any color on where your wish list would be?

Craig, I think from the NGL perspective as we look at -- we want to have something that is complementary to the assets that we already have. Something that bolts on. Obviously, from a resource play, the Permian is a very good play with West Texas pipeline, but in other areas, anything we can put into our system, to be able to continue that integrated chain is what we will be looking at.

Okay. Thank you very much.

Danilo Juvane, BMO Capital Markets.

Most of my questions have been hit. I have one quick clarifying question, though.

With respect to you having more visibility to distribution and dividend growth in 2017, do you have a sense for what that magnitude that could be at OK gas and OK?

No, we're not going to provide that information. As we go through our planning process here for 2017, we are in the middle of that process now. When we issue guidance, maybe we will provide a bit more specificity for you. We are not prepared to do that at this point in time.

And as you evaluate the fundamentals potentially changing, you said this growth was contingent on fundamentals remaining intact. What specifically are you monitoring in terms of making that decision?

Certainly the overall industry climate, commodity price environment, how our producers are feeling, how are they spending their capital, the petrochemicals phase, are they on schedule with their petrochemical plants. And just the general climate, the industry, and in particular, our business.

Okay. That is it for me. Thank you.

It appears there are no further questions at this time. I would like to turn the conference back to Mr. Eureste for any additional or closing remarks.

Thank you. Our quiet period for the fourth quarter starts when we close our books in early January, and extends until earnings are released after the market closes in late February. Thank you for joining us.

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