歐尼克 (OKE) 2017 Q4 法說會逐字稿

Good day, and welcome to the Fourth Quarter 2017 ONEOK Earnings Call. Today's call is being recorded. At this time, I would like to turn the call over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you, Ebony, and good morning, everyone. And welcome to ONEOK's fourth quarter 2017 and year-end earnings conference call. A reminder that statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision 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 this morning is Terry Spencer, President and Chief Executive Officer. Terry?

Thanks, Andrew. Good morning and thank you all for joining us today. As always, we appreciate your continued interest and investment in ONEOK.

Joining me on today's call is Walt Hulse, Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs; Kevin Burdick, Executive Vice President and Chief Operating Officer; and the Senior Vice Presidents of our business segment also are available for questions.

On this call, we will focus on fourth quarter and year-end 2017 financial results and provide some additional color on our strategic and accretive growth projects, including our recently announced Arbuckle II pipeline, MB-4 fractionator and Demicks Lake projects. We previously provided 2018 guidance in January.

2017 was an important year for ONEOK. We completed the ONEOK and ONEOK Partners merger transaction in June and the benefits of that transaction are paying off for ONEOK and its shareholders, particularly as we invest more than $4 billion in strategic expansions of our existing integrated network of pipelines, plants, fractionation and storage facilities with more favorable access to the financial markets as a result of the merger and our continued focus on generating attractive returns. That was proven by an extremely successful traditional equity offering in early January that prefunded the projects that we have recently announced. From an operations perspective in 2017, I again want to thank our employees who personally endured Hurricane Harvey and countless others who worked tirelessly to keep our assets running safely in order to provide reliable services to our customers, not only during the hurricane, but every day. The dedication and commitment of all our employees to this company is remarkable and I very much appreciate their hard work in making our company successful.

Moving onto our 2017 performance. For the fourth quarter and for the full year, producer activity and production results drove volume growth in all our business segments through our operating footprint, which led to adjusted EBITDA and distributable cash flow growth. The recent completion of 2 world-scale petrochemical crackers will continue to increase demand for ethane in the Gulf Coast as these facilities complete their start-up activities. In addition, 4 more crackers, with a total capacity of nearly 200,000 barrels per day of ethane, are expected to be completed later this year. As outlined in our 2018 guidance, this additional demand for ethane is expected to drive approximately $100 million of additional EBITDA in our NGL segment compared with 2017.

After saying for a few years now that new petrochemical facilities and ethane crackers are being built, it is now evident in the marketplace that the incremental demand for ethane is here. Our focus remains on executing our attractive growth projects to meet the needs of our customers in Williston, Powder River, DJ, STACK, SCOOP and Permian Basins. Over the last decade, ONEOK's experienced operations, construction and commercial teams have successfully executed $9 billion in capital investments, aggregating supply and delivering it to the market safely, reliably and in an environmentally responsible manner.

With that, I will now turn the call over to Walt.

Thank you, Terry. ONEOK's 2017 operating income totaled nearly $1.4 billion and adjusted EBITDA totaled nearly $2 billion, [7%] increases compared with 2016 and more than 25% increases compared to 2015, all driven primarily by strong volume growth. And we expect to see that growth continuing with adjusted EBITDA increasing more than 15% for 2018 compared with 2017. Distributable cash flow was nearly $1.4 billion in 2017, and dividend coverage of more than 1.3x was well above our guidance of 1.2x or greater for the year. This month, we paid a quarterly dividend of $0.77 per share or $3.08 per share on an annualized basis, a 25% increase compared with the same period in 2017. Management still expects to recommend dividend increases of 9% to 11% annually and maintain our target for annual dividend coverage of 1.2x or greater.

As noted in our earnings release, fourth quarter net income included $141 million of onetime, noncash charges related to the Tax Cuts and Jobs Act, which impacted fourth quarter earnings per share by $0.36 and full year earnings per share by $0.47. We view the overall impact from that Tax Cuts and Jobs Act as positive to ONEOK due to the lower corporate tax rate and the immediate expensing of most of our capital spending.

As Terry mentioned, we've announced more than $4 billion of new capital growth projects since June. These attractive investments are expected to generate adjusted EBITDA multiples of 4x to 6x and are backed by a combination of long-term, fee-based contracts, volume commitments or acreage dedications. Based on these recent project announcements, ONEOK's 2018 capital growth expenditures are now expected to range from nearly $2 billion to $2.3 billion, an increase of approximately $700 million compared with our initial 2018 guidance.

Maintenance capital guidance remains unchanged at $140 million to $180 million. We've talked quite a bit about the funding of these highly accretive growth projects and how we essentially prefunded our equity needs. In the fourth quarter, we received net proceeds of $384 million through our ATM equity program, and completed a $1.2 billion public common stock offering in January, resulting in a total combined net proceeds of approximately $1.6 billion. With the expected significant cash generated from operations and excessive dividends and ample borrowing capacity, we don't expect to issue any equity in 2018 or well into 2019. Following the equity offering in January, ONEOK's pro forma debt-to-EBITDA on the last 12-month basis improved to just under 4x, and put us at our target a year earlier than we expected. We expect our leverage to increase modestly during the later stages of the construction but we continue to view 4x or less as an important target for ONEOK over the long term. Our anticipated EBITDA growth in 2018 will enable us to fund our growth with excess cash flow from operations in short- and long-term debt while maintaining strong credit metrics.

As it relates to the review of rates on West Texas LPG, the regulatory process continues and it will resolve itself in due course. Our 2018 NGL segment financial guidance encompasses a range of potential outcomes for the (inaudible) provision. The midpoint of our NGL segment adjusted EBITDA guidance does not assume any uplift from potential rate increases. As we said previously, the outcome of which will not impact our current or future negotiated rates on West Texas LPG, nor will it hinder our ability to secure new NGL supply from producers and processors, including our project which extends West Texas LPG into the core of the Delaware Basin as we continue to actively negotiate with producers in the Permian for additional capacity.

And now I'll turn the call over to Kevin for a closer look at each of our business segments and to provide some additional color on our growth projects.

Thank you, Walt. Starting with the performance of our natural gas liquids segment. 2017 was another year of strong volume growth, setting us up well for even greater growth in 2018. Fourth quarter 2017 NGL volumes gathered averaged 867,000 barrels per day, a 7% increase compared with the third quarter 2017, and a 17% increase compared with the fourth quarter of 2016. Higher overall raw feed volumes on our Mid-Continent and West Texas LPG pipelines drove the sequential quarter increases, with Mid-Continent volumes increasing more than 9% during that timeframe. Mid-Continent growth continues to be driven by strong producer results in the STACK and SCOOP areas.

Our Bakken NGL Pipeline is operating at full capacity as volumes averaged 136,000 barrels per day in the fourth quarter 2017. Our recently announced Elk Creek pipeline project will alleviate NGL capacity constraints out of the Rocky Mountain region once complete, and we expect to use our rail transport capabilities as early as the second quarter 2018 to provide the necessary takeaway for expected volume growth until Elk Creek is in-service.

NGL volumes fractionated in the fourth quarter 2017 increased 13% compared with the third quarter 2017 driven by higher gathered volumes across our NGL system and lower volumes fractionated in the third quarter due to impacts from Hurricane Harvey. Volume that could not be fractionated during the third quarter because of the hurricane were stored and fractionated in the fourth quarter. Our NGL volumes were in line with our guidance range even with petrochemical cracker completion delays and the impact from Hurricane Harvey.

Moving on to the natural gas gathering and processing segment. We exceeded our 2017 financial guidance expectations due to the strong producer results in the Williston Basin and STACK and SCOOP areas. The segment's fourth quarter 2017 average natural gas gathered and processed volumes increased 20% compared with the same period in 2016. Fourth quarter volumes processed increased 5% compared with the third quarter 2017, averaging nearly 1.7 billion cubic feet per day across our system.

Williston Basin volumes processed again established new highs with an average of more than 870 million cubic feet per day during the fourth quarter. Mid-Continent process volumes averaged more than 790 million cubic feet per day, a 6% increase compared with the third quarter of 2017. We exceeded our well connection expectations for 2017 in both the Williston Basin and the Mid-Continent, connecting 430 and 113 wells, respectively, and we expect to connect approximately 650 wells total in 2018, a nearly 20% increase from last year.

In the Williston Basin, continued producer activity, improving well performance and higher gas-to-oil ratios are driving volume growth. Analysis of recent well results shows that 25 to 30 rigs today can produce as much natural gas volume as 70 to 80 rigs 3 years ago. With now only 100 million cubic feet per day of available processing capacity on our system, our recently announced Demicks Lake processing plant will provide producers in the region with much-needed processing capacity to accommodate their growth expectations.

Volume growth in the Mid-Continent in the fourth quarter 2017 was driven by strong producer results in the STACK and SCOOP areas, which led to a 6% increase in natural gas volumes processed compared with the third quarter 2017. Our third-party offload is operational, which provides us access to an additional 200 million cubic feet per day of processing capacity for our growing volumes in the STACK, and we're on track to add an additional 200 million cubic feet per day of capacity in the fourth quarter this year with the expansion of our Canadian Valley plant. Once complete, we will have approximately 1.1 billion cubic feet per day of processing capacity in Oklahoma.

In the natural gas pipeline segment, 2017 adjusted EBITDA increased 9% compared with 2016. The segment continues to benefit from higher fee-based earnings and increased transportation capacity contracted. The segment continues discussions with producers in the Permian basin and in the STACK and SCOOP areas to accommodate additional natural gas Takeaway capacity given the strong growth expectations in those plays.

Recent tax reform laws have spurred conversation around potential impacts for regulated pipelines. For ONEOK, since most of our natural gas pipeline contracts have been established through shipper-specific, negotiated rates and settlements, we don't anticipate adjustments to rates solely because of lower tax rates. Related to rate settlements, on February 23, Northern Border Pipeline received a letter order from the FERC approving their uncontested rate case settlement without modifications.

Now let's take a closer look at our recently announced capital growth projects and how these latest projects complement and enhance our previously announced investments. This year, we've announced 2 strategic NGL pipeline projects, Elk Creek and Arbuckle II. The 530-mile Arbuckle II Pipeline will have an initial capacity of 400,000 barrels per day and has the capability to be expanded up to 1 million barrels per day with additional pump facilities, which could more than double our current capacity between the Mid-Continent and Gulf Coast with minimal capital investment. We're also adding 125,000 barrels per day of additional fractionation capacity at Mont Belvieu with the announcement of our MB-4 Fractionator. The Arbuckle II Pipeline is already more than 50% contracted and will provide producers in all the basins where we operate with connectivity to growing demand in Mont Belvieu. The adjusted EBITDA multiples forecasted for these projects are based only from these contracts and discussions with customers regarding additional supply continue to take place.

The MB-4 Fractionator is already fully contracted and both projects are expected to be complete in the first quarter of 2020. Our Demicks Lake plant will add an additional 200 million cubic feet per day of processing capacity in the Williston Basin, bringing ONEOK's total capacity in the region to more than 1.2 billion cubic feet per day in the fourth quarter 2019. Additionally, we are in the permitting process for an expansion of our Bear Creek processing facility that we expect could add 40 million to 60 million cubic feet per day of capacity with minimal capital. NGLs from the Demicks Lake plant will ultimately feed our Elk Creek pipeline, which in turn will connect with ONEOK's extensive Mid-Continent NGL gathering system, which provides connectivity from the Williston Basin to the Gulf Coast.

A quick update on our Elk Creek pipeline announced in early January. We continue to have discussions with producers and processors to secure additional supply out of the Rockies region. And our outlook now exceeds our original volume expectations by 10% to 20%. We continue to proactively communicate with landowners, state and local agencies and other stakeholders along the pipeline route and expect to begin construction later this year. All of these strategic attractive, return projects will work together to provide much-needed solutions for producers and position ONEOK with considerable long-term operating leverage across our integrated network of assets.

Terry, that concludes my remarks.

Thanks, Kevin. Before we take your questions, I've got a couple of items to point out. As I mentioned earlier in my remarks, ONEOK will be laser focused on executing on our $4 billion of announced growth projects over the next several years, so -- which will take us to 2020. As we look beyond 2020, I'll go ahead and answer the question some of you may be in line to ask and that is what's next.

As Kevin detailed, many of our projects are being designed with the ability to expand significantly with minimal capital investments and we will continue to develop opportunities in and around our asset footprint to expand even further, whether that be through pipelines, processing plants, fractionators or storage, all of which we've proven we know how to manage, build, operate and optimize.

So with that, operator, we are now ready for questions.

(Operator Instructions) And we'll take our first question from Shneur Gershuni with UBS financial.

Just wanted to start off with the new projects announcements. I guess, a 2-part question. First of all, you had mentioned I believe in your prepared remarks about contracts backing the new pipeline build. I was just wondering if you can clarify, are the minimum volume commitments or the acreage dedications, is there a way that we can sort of split that up? And then sort of the second part of that and I think you kind of just answered it, does this take care of all the large ticket project announcements that were kind of highlighted in the filings when you did the OKE-OKS merger?

Sure, I'll start, this is Kevin. As it relates to Arbuckle II, those volumes in the contracted capacity, there's not a lot of MVCs associated with that. They are in the form of plant dedications and acreage dedications and so forth. On the big ticket items, yes, I think this handles the majority, it sets up significant operating leverage or headroom, like Terry mentioned in his remarks, going forward. So we feel pretty good about the assets we have in place to be able to grow into the future.

Shneur, I'll let Walt handle the question about the filing on merger.

Shneur, at the time of the S-4, we did not have any of these projects contemplated. As we went through the course of '17, we started to talk about our backlog and with the announcement of these projects. Here recently we've announced all of the projects that we have in that backlog, and we'll start to look for future opportunities.

Okay, great. And just a follow-up, ethane recovery versus rejection has been a topic for some time. There's kind of an interesting developing market dynamic where you look at gotten natural gas capacity beings scarce in the Permian and at times, we've seen some sizable differentials between Waha and Henry Hub. It could create a scenario where the economics of recovering ethane becomes greater in the Permian than any other basin in the country, and there's the possibility that Permian ethane recovery crowds out other basins. How is ONEOK positioned if this materializes? Is it offset by the full-scale system that you have in place? Or is there some risk to meet the 100 million plus of ethane recovery that you're looking for this year?

This as Kevin, I'll let Sheridan chime in as well. I mean, as you look at Waha and what's going on with the basis market, the interesting thing is Mid-Continent basis has been extremely wide too and right there with Waha. So that's one dynamic when you think about our significant position in the Mid-Continent. The other thing that's going on is, based on our analysis, we don't think that there's you're not going to be able to recover enough ethane solely out of the Permian to satisfy the additional demand that's going to be coming online in the Gulf Coast. So even if Waha did have a wider basis, you're still going to need ethane coming out of the Mid-Continent. Sheridan.

That's right, that's exactly right.

(Operator Instructions) We'll move next to Eric Genco with Citibank.

Just wanted to follow-up on the last question to make sure I understand. You've got the $4.2 billion of projects and I think the understanding was some of that -- I mean, the S-4 forecast was based on sort of ongoing CapEx in that range. So maybe you could say frac, processing some of that was ongoing. But the 2 major pipelines, Elk Creek and Arbuckle, are strategic and were not included, correct?

Yes Eric, this is Walt. I think it's actually fair to say that at the time of the S-4 what was basically in there was our routine growth, which included well connects, plant connects on the NGL side, just our base growth without the processing or fractionation. As we talked about our developing projects over the course of '17, those included both the fractionation and the crackers and plants.

Okay. So looking out now at the -- if at I look out at the consensus for 2021, that's actually below what was in there. And I don't want to spend too much time making the S-4 sort of a pseudo-guidance. But if 2021 consensus is below the S-4 and just the $2.8 billion of CapEx for the project at 6x S-4 $460 million of EBITDA. And then I guess, oil, I mean, oil right now at least is above the forecast for where it would have been, is there anything that you can think of that would be in any way worse than the S-4 forecast? That might...

No I think it's fair to say that the S-4 was a snapshot at a point in time that kind of reflected our view in November of 2016. And, obviously, commodity prices are better, producer activity is better. (inaudible) across-the-board, we see fundamentals of the business in a better spot today than when we did when we filed that S-4.

Okay. And then maybe another quick one. Did you say how long at this point in time under the new tax code you expect to avoid cash taxes at the OKE level? Was there an update on that?

We did not say. But our view hasn't changed from what we've previously said.

Okay. And then maybe a last one for me just want to try to understand. I think you mentioned in the prepared remarks, what happens between now and Elk Creek in terms of the NGL takeaway? If we think of you as being the only game in town from a pipeline perspective, I know you mentioned rail, how should we see that sort of playing out in between now and when Elk Creek comes on in terms of the bundled rates? Is there a different way that we should be modeling that? And how that growth will likely flow through to the bottom line?

Eric, this is Sheridan. As we put the barrels on the rail, we probably won't have a whole lot of margin left in those barrels. Basically, all we're trying to do with the rail is provide our customers a way out of that volume. So there will be minimal uptick in margin on that as we get there. But once we bring Elk Creek on, we'll turn all that into margin for the pipeline.

Our next question will come from Kristina Kazarian with Crédit Suisse.

You guys have announced a lot of projects this year and I mean, it's only February. So can you talk a little bit about the longer-term magnitude and cadence? And I know, Terry, you've kind of alluded to some of these comments in your opening comments. But magnitude and cadence of new projects that maybe you'd love to do, but haven't announced yet. Not what they are but just how we think about the year, next year kind of evolving around that topic?

Well, certainly, we haven't just stopped because we've announced all this -- we brought to reality the backlog of projects that we've been talking about for about the last year. We haven't stopped developing new opportunities. We continue to work hard around our existing footprint. And certainly as we've always done, as those projects, beyond just 2019, 2020 timeframe, as those projects continue to get more visibility, then we advise the Street. We let you know as we get more clarity, as we get closer. And certainly, our past practice is as we start contracting for those projects or unannounced projects, we come out publicly with them. And so we're going to continue to do that and certainly, we still are finding opportunity and some of it isn't just gathering and processing and shipping NGL, some of it are other projects and we've talked about export opportunities, so we continue to work that front very hard. So we've got a number of other opportunities in the queue but certainly, not ready to announce anything yet.

Got it. Framing it up from my standpoint, is there like potential for more announced this year? Or should I be thinking more potentially skewing into next year and forward?

There's always a potential for more projects. But I'll tell you, the projects that we've just announced certainly position us with plenty of capacity for running room for growth. So there's not a whole lot of need for more infrastructure, but there could be. We continue to see the positive move in volumes we're seeing. There could be a potential for some things later on in the year, perhaps not of the magnitude that we just announced. But we certainly always have that opportunity or that potential rather.

Last one for me, following up on that kind of -- you got pretty significant amount of NGLs heading down towards your downstream assets. How are you guys thinking about the end markets for purity products coming out the other side of your fracs, and maybe alluding to your export comment there as well?

Kristina, this is Sheridan. Obviously, we think as more and more propane and butane come online, they will have to be exported. And in the short term, we think there's plenty of export dock capacity down there in the Gulf Coast to be able to handle this as it comes on. We definitely see 2 or 3 years out that there will probably need to be more LPG exports out of the Gulf Coast. We also talked about on the ethane side that -- the 3 big crackers that everybody's been waiting for have now -- are up and running or have reached mechanical completion. And we're into the second portion of that later this year. So we'll see a lot more demand on the ethane tide coming at this period of time. We still see a lot of opportunity for additional ethane exports out of the Gulf Coast as you start looking out more in that 3 to 5 timeframe. So that's really how we kind of think about what the purity market's going to look like for our NGLs down at Mont Belvieu.

We'll take our next question from Brian Zarahn with Mizuho.

With your expectation of 4x to 6x multiples on your new projects, can you elaborate a bit on the timeframe? Is that a year 1 expectation? Or is that following a ramp-up period?

Brian, this is Kevin. Yes, that's not going to be a year 1 thing because obviously, as these assets come on, they're going to ramp-up with volume. But we would expect to get there kind of our current volume outlook. I'd say in 2 to 3 years as we move through that. Obviously, if we continue to have success contracting and bring more volume on, that could accelerate.

And then on Elk Creek, obviously, it's a Bakken-driven project. But could you elaborate a little bit on the comments earlier on the opportunity in the DJ and Powder River?

Yes. We're seeing strong, we continue to see it's not just our equity G&P business in the Bakken that's seeing growth up there. So we're having success there in the Williston with third parties. You come down to the Powder River, there's been some announcements here recently as far as additional rigs and some acreage has changed hands and now it's getting drilled out a little more. So there's been more activity going on in the kind of a Niobrara/Powder area. And then you get down to the DJ, we're seeing growth there as well. And so with a combination of our assets with Bakken and Elk Creek, we're in a great position to contract up that business. Terry.

The only thing I'd add is when you see a lot of those rigs coming in, especially in Powder River we don't talk as much about that, most of those rigs are coming on acreage that's already dedicated to us through existing contracts.

Okay, appreciate the color. Shifting gears to the Permian, any update on your discussions with potential customers on your West Texas LPG expansion project?

Yes. We still continue to talk to customers out there. We're still in various levels of discussion with them in contract negotiations obviously, that's a very competitive area out there. But we think we are advancing those discussions. And when we get them, when we get ink on paper, we'll let people know we have more capacity to be constructed out there. But we think everything's going as planned on that front, but it is competitive and we are working on multiple sites for new plans.

And the last one for me on expansion CapEx this year, it's a little bit of wide range. What are some of the moving parts? Is it permitting? Is it weather? Is it some other smaller projects? And do you expect CapEx to be back-end loaded this year?

Yes. We will absolutely ramp-up through the year with our CapEx spending. As far as what's driving the range, it's clearly timing. I mean, we have plans and we think will be in the middle range there. But whether it's weather or some minor delays or acceleration, that could move capital around when you've got the number of projects that we're going to be working on, especially in the back half of the year.

Kevin, I think the only thing I would add to your comment is that, we've got a lot of experience building pipelines across this country and so -- and we've had weather situations with just about every one of our projects. Still, we've got experience at factoring in those kinds of things that you don't always anticipate that affect a project. And we've certainly done that here in the capital estimates that we provided so we've used all that experience and data that we've accumulated and factored that into these estimate so we should be in pretty good shape regardless of what happens.

We'll have our next question from Christine Cho with Barclays.

For the initial 50-plus percent of the Arbuckle II Pipeline that's contracted. How many new plants are going to be connected to the lines to get to the 200,000 barrels per day? Can you give us any more color on how much of it is third-party plants versus your plants? How much of it is volume from Elk Creek selling into the line versus volumes you're picking up in Oklahoma or West Texas? If that's also an option for supply connection?

Christine, this is Sheridan. What I would tell you is typically a 200 million a day plant's going to produce 20,000 to 25,000 barrels a day. We do have obviously, some of our plants are in there from the SCOOP and the STACK, but by far, the majority of the plant that we'll be connected in the SCOOP and STACK will be third-party processing plants. So most of the plants you're hearing being announced today are contracted to this system. The Arbuckle II Pipeline is a pipeline that provides capacity to all systems. So we do have some transport-only volume on this system, some of that volume will come off at Elk Creek. But that is Elk Creek economics are from the Bakken to Conway. And if it was a volume that's going to end up in Mont Belvieu, then the additional fee to get from Conway to Mont Belvieu will be applied to Arbuckle on that piece as well. So that's why you're seeing that part of the 200,000 plus barrels will be transport only, and majority of it will be fracking down in Mont Belvieu with the additional frac capacity.

But are you assuming some of the Bakken in that 200,000 barrels per day or that would be excess?

We are assuming some of the Bakken in the 200,000 barrels a day.

Okay. And then what's your utilization on the Sterling and Arbuckle pipelines currently? The spread between Belvieu and Conway has widened out. So curious to know if you think this is a short-term phenomenon or is the beginning of continued widening until more capacity comes on? And does it seem like customers are wanting to sign up for long-term capacity well ahead of their needs more today than what you've seen the last 2 years?

So Christine, Arbuckle Pipeline is fully -- we are moving as much volume out of the Mid-Continent as we can on Arbuckle Pipeline. So you'd say, for movement out of Mid-Continent, Arbuckle's 100% utilized. On the Sterling system, we are about 60, a little over 60% utilized, if you put in that Sterling III will be expanded to [250]. So we already put that volume in, we're about 60% utilized, 60% to 70% utilized on the Sterling system. We do think spread, they're not going to be where they are today. You're seeing an unusual spread differential here at the end of February where you're seeing $0.30 some spread. If you look ahead into next month, they get back more into $0.07 to $0.10. We think there's a possibility that could stay in that range, especially as we see more ethane come online and fill up a lot of that Sterling space, which you will constrain some of the space, but you are right, we think that could stay there until we bring on more capacity and that more capacity will be Arbuckle II.

Okay. Great. And then I think you're kind of addressed this in your prepared remarks, but we heard one of your G&P competitors talk about one of their future plants connecting to your Bakken line. Was that included in your 100,000 barrels per day of commitment for Elk Creek? Or is that incremental?

Well, I would say that's included in our prepared remarks that we announced that we are 10% to 20% higher than what we had originally said was the volume we had contracted on the line.

Our next question will come from Jeremy Tonet with JPMorgan.

Just wanted to start off with operating in the NGL results there. The optimization in marketing, I think it was down a little bit quarter-over-quarter. But as you were talking about the (inaudible) widening a bit here, just wondering if you could expand a bit on the commentary? It seems like there's offset by wider location (inaudible). And how you see that playing out and when you're looking at the NGL segment guidance over the course of 2018. What type of environment do you see for that versus kind of what we're seeing right now?

Are you referring to the sequential quarter-to-quarter optimization in marketing, Jeremy?

Yes.

Okay. What's going on there is if you think back, we really had a very strong Q3 in optimization and marketing. And then it wasn't that the fourth quarter was bad, but just from some timing things. We ended up, it was lower so it was really the strong third quarter that drove the sequential fourth quarter being down.

Great. And as you think about your 2018 guide, does that (inaudible) and environment, that's similar to what you're seeing now in those different factors? Or is it much different?

This is Sheridan, the $0.03 to $0.04, I mean, is what we put out there is kind of the spread that we use for ethane for our optimization. And yes, we've seen some short-term things that are positives here in the first quarter. But does that continue through the rest of the year? We don't have that type of spreads we're seeing today built into our '18 guidance.

Great. And think about your pipes going into Mexico there, just wondering given the state of Waha basis as you described, where the volumes are now on that pipe? When could that hit full utilization? And what do you think the prospects are as far as maybe moving more that gas further into Mexico over time given such ramp in supply growth in the Permian?

I think the key in our West Texas in our Roadrunner pipeline regardless of the physical flow, that's a long-term firm commitment, demand charge we're getting paid regardless of the volume that are flowing. I mean, as the downstream infrastructure continues to get built out in Mexico, then we will see more physical volumes flow. Timing of that's probably over the next 1 to 2 years. Phill, anything to add there?

No, that's exactly right. And we continue our conversations with markets in Mexico about expansion capabilities of Roadrunner II. So they're obviously, looking at the Waha pricing and seeing that, that's pretty attractive to what they're trying to do.

Phill, it's Terry. It's fair to say that as least as far as [CFE] is concerned specifically as it relates to Roadrunner that they're still constructing or still in the construction phase in some of their power plants and those have been slow coming, right? And so certainly as we move throughout the balance of the year, some of the Norte power plants, some of those plants that are making progress on. And certainly as those plants get further along or get operational, we'll see increased loads on Roadrunner.

Absolutely. Yes, they continue their construction activities on their power plants. And even in addition to that, there's a pretty robust construction activity on the downstream pipeline side in Mexico right now. So a lot of those facilities will be coming online in the next year or so. And you'll see some increased supplies coming in from Waha and the states supporting those facilities. But as Kevin mentioned, our facilities are already contracted, they're take-or-pay contracts and so we feel good about our position there.

Great. And you guys noted I think 650 completion count for next year, was just wondering or for 2018. I was just wondering if you might build or expand a bit on some of the drivers or details to that. And it seems like some of the producers this quarter were talking about Mid-Con growth or STACK growth, maybe a little bit slower than what they had messaged before. Just wondering if this kind of matched your expectations there?

This is Kevin. Yes, we haven't seen anything come out. In fact, we've been quite pleased with the producers have gone through their calls and talked about their capital spend for '18 in both the Williston and the STACK and SCOOP, and it's all been absolutely in line with our guidance and our outlook on things. So the 650 we still very good about that given what we're seeing from the recent capital announcements.

That's helpful. And then Jim, just one last one, seems like where your leverage sits, liquidity sits, surely you guys enjoy some financial flexibility, I think others in this space still don't have yet. And just wondering if you had thoughts as far as industry consolidation or M&A in general, if that's something that's on your radar at all? Or just given the deep, deep organic growth opportunities at really great rates of return if that's just kind of not as much of a high priority for you guys right now?

Well, certainly the organic growth strategy that we talked about today is what we're focused on. Okay? So as far as the M&A front goes, it's certainly difficult to predict and actionability is always a challenge. And certainly our company is well-positioned in any event, a compelling opportunity presented itself, we'd be ready. But candidly, with the organic growth opportunities that we see out in front of us over the next 3 to 5 years, we are not in a position to have to do any M&A. So hope that puts that where it belongs, in terms of priority.

We'll move next to Chris Sighinolfi with Jefferies.

You closed your prepared remarks mentioning sort of what comes next and my first question is related to that but, specifically with regard to the fractionation portfolio. The 4Q results indicate headroom of about 150,000 barrels a day on the current capacity, and MB-4 will obviously add about 125. But you have significant committed volumes you've spoken about on the new NGL pipes and ethane recovery might be gravy on top of that. So I'm just wondering if we could talk about how on the frac side everything takes shape. Is it sort of strongly hinting about additional frac capacity that you'll add over the same time frame? Or do you have legacy contracts rolling off? Or do you contract for capacity you might need? Are you responsible to frac all the volumes on your line, can you just walk us through that?

Let's let Sheridan answer that question.

So I think the first thing you have to look at fourth quarter fractionation volumes are really higher than they should be due to, as we said, the third quarter being less than they should be, and we had a lot of stored volume coming into fourth quarter. So you have some more room in there as well. But we think with what we have we do have some volume on our system that is transport only. We have some fairly large projects that we did move the volume for people that have fractionation capacity in the Gulf Coast area that we have done as well. So we don't have to frac all the volume that's on our system. As we said, our current MB-4 fractionator is fully contracted. So as we continue to grow with contracts with our customers, there could be another fractionation and we hope there's another fractionator that comes online in the near future.

And Sheridan, I guess related to that then, should we expect any upward pressure over the next couple of years on frac fees at Belvieu? Or as you see the cadence of new plants from you and from peer companies, is there enough capacity coming online that you don't think will be pinched?

Well, I think a lot of times you think about when you contract and build a fractionator, you have to -- you're going to build like our MB-4, we're going to build 125,000-barrel a day fractionator, and that capacity comes online day 1. But we ramped into that capacity from our commitments as it ramps over 2 to 3 years. So in that, everybody is in the same boat, so there's going to be some capacity in the front that -- and the industry will have as we ramp into these contracts. So I think we won't at this time, get pinched on capacity. Overall, I think rates will be somewhat where they are today because when you look at really fractionation rates, you can't just look at what's going on in Belvieu. Most people are competing for the bundled service out in the fields. We're competing in the Bakken, the STACK and all that -- that's where we're getting a bundled service. And when we look at what the market is in that area, not necessarily what the market is in Belvieu.

Okay. And I guess the final question on the frac front. Will there be any rationale or opportunity to build additional frac in the Mid-Con? Or is it just logical to think that all new frac capacity is going to be Belvieu eccentric?

We really think it's going to be Belvieu eccentric. One of the main reasons is we think it's easier to ship raw feeds than it is to turn it into byproducts and pass it down a pipeline. And Belvieu's where we see the -- Belvieu or the Gulf Coast is where we see incremental demand. We may put -- the only thing we do for some fractionation capacity in the Mid-Con is if we could do it at a relatively cheap, small expansion rate what you saw a little bit on what we're doing on Elk Creek pipeline. We're spending a little bit of money to upgrade our fracs, but that's cheap capacity expansion. Any new greenfield will all be built on Gulf Coast.

Okay. And I have one unrelated question which dovetails back on Jeremy's inquiry about the optimization in marketing. Kevin, appreciated your answer, just in the (inaudible) -- it indicated narrower product/price differentials were a partial offset to the wider locational differentials. Were you -- is there an activity there where you're supplanting propane for butane or butane for propane, can you just talk us through that?

Really, what you're doing when we talk about product/price differentials, is the time we buy and sell and timing of the market, and so (inaudible) volume in the third quarter, big, nice price in the third quarter not as much in the fourth quarter so that's really what we're talking about there.

We'll take our next question from Ted Durbin with Goldman Sachs.

Coming back to the return profile on the projects, what drives the difference between the low end and the high end of the range, the 4x to 6x? Is it more on the total capital you spend? Or I would think more on the volumes that actually show up or operating cost, maybe you could just give a sense of what drives the levers at the high-end?

It's Kevin. It's going to be primarily timing and just your volume ramp. I mean, again, at the high-end of that range, you're going to be earlier on and with our current contracted capacity, if those volumes come on faster and/or you get some more contracts, you're going to push that multiple lower.

Okay. Just coming back to the ramp then, is it fair to say that the first year is going to come in at 6x? Or is it even maybe higher than that? I guess, a little more color on the ramp and where we start out in the first year?

I mean, yes, in the first year, again if they're coming on at the beginning of the year, by the end of that year, you might be towards that high end. I mean, but again that's going to be kind of splitting hairs a little bit as far as when exactly the volumes come on inside that first year. But that's the way I would definitely think about it that way is that, early on, especially in the first year and years 1 and 2, you're going to be at that high-end and then it's going to transition down as you fill it up.

That's helpful. Just on the guidance in the gathering and processing, you're guiding to $0.80 rate, that's down from $0.86 in 2017. Is that just a mix shift between the Bakken and the Mid-Con? As you think ahead into 2019, should we expect that rate to be kind of a good run rate? Or how do we think about that gas gathering rate?

Chuck, you want to that one?

Yes. Kevin, I'll take that. Essentially what that is, it's the Mid-Con in volumes coming on and our feeds are lower in the Mid-Con than they are in the Bakken. So that's kind of the blended rate between the 2 basins.

Okay, great. And then last one for me, just coming back to the financing, well, you mentioned that you're close to where you want to be but you think the leverage ticks up over time obviously, with the higher CapEx. I guess, what's the comfort of the rating agencies to let you get into the mid- to high 4s, let's say, and still keep that BBB rating? Do you need to come for, I don't know, preferred equity or turn on the DRIP? Are there other things you can do just give us a sense of kind of where we should see leverage trending into '18 and '19?

Well, I'll let the rating agencies speak for themselves, but I will say that we have had constant dialogue and keep in touch with them on a regular basis so they're well aware of what we're doing. And yes, as we get these construction projects towards the end of '19 coming on, we'll see some pickup in our leverage above that 4x. I don't think it will be at the high end of the range you just mentioned. But as these pipelines come on, and there's cash flow, our credit metrics improve dramatically and we'll be back through that 4x target pretty quickly. So just given the transparency of these contracted volumes and how we see that playing out, we think that as far as our discussions with the agencies, we're pretty comfortable with that. If we have other projects come on, and we need to think about some equity out there in '19, we're leaving that door open. But as we sit here today, there's a good chance we won't have to issue any other equity.

Okay, great. And last one for me is just on your management incentives. In your Proxy Statement as you develop the next one, are you going to keep a return-on-invested capital metric in there at the OKE level from what you had at OKS, what should we look for in terms of those metrics?

Yes, we will.

Our next question will come from Craig Shere with Tuohy Brothers.

Kevin, sorry to beat this into the ground. But that 2 to 3-year ramp at 4x to 6x EBITDA, I'm thinking specifically around Elk Creek. I thought that, that you had about 70,000 barrel a day of MVCs that hit just about right away, with maybe another 30 that rolled in over a year or 2. And so I just want to confirm that's about right? And also see if this rail volume Sheridan is talking about having no margin is basically, the same as the MVCs? Or do you see that as potentially incremental that could be day 1 margins as soon as Elk Creek comes up?

Okay, this is Kevin. A couple of questions in there. So on the one clarification, on the 70,000 barrels a day minimum, we said we had the volume commitments on out of the 100,000, that 70,000 barrels a day ramps also. So that all that doesn't hit day 1. So that's one dynamic that's going on. Yes, as we rail volumes and as the volumes we put on rail grows over the next couple of years while Elk Creek gets built, then absolutely day 1, those volumes would shift over to the pipe and drive that incremental EBITDA very quickly. So that's the way, I guess, to think about how the volumes will grow, but then you will have an initial EBITDA pop when Elk Creek comes online as you move these rail volumes over to the pipe like Sheridan mentioned. Did that answer your questions?

It does. Can you clarify how much capacity you can handle via rail? And do you all intend to advise us over time how that portion of the business is growing so we can kind of model the EBITDA uplift once Elk Creek hits?

Yes. We have said, we expect to be able to rail up to 30,000 barrels a day from our River View facility in -- up north. And so you can then kind of back end, okay, what would that mean if you're railing 30,000 barrels and then you've got the rates we're getting?

Sure. Would you anticipate that to be relatively full by the time Elk Creek is online?

Yes.

We will now take our next question from Ethan Bellamy with Baird.

A follow-up to Jeremy's question about your now excellent cost of capital but from a different angle. Do you have any desire to vertically or horizontally integrate, for example, maybe heading to the northeast on the gas and NGL side, or maybe moving downstream to LNG?

Yes, not really. We thought about the northeast from time to time, in particular in the Marcellus region. We've got some NGL assets, they're kind of in the regions, but not really suited to serve any Marcellus development, that's primarily our North System in our NGL segment. We pondered the Marcellus for some time, but candidly it is well served by midstream companies with really strong positions. So we don't see a spot there for us. And on the LNG front, we're more interested in the infrastructure upstream, and that's what we continue to work on pipeline, storage and those types of things that would serve LNG, but not a particular interest in being in LNG plants. So that's kind of how we think about those things in particular.

Okay. And then, just one sort of housekeeping question. Was there any -- maybe what you describe as a normally high amount of freeze-offs or anything weather-related in the first quarter that we should be modeling?

No, I don't think we've seen anything kind of out of the ordinary. Like we have talked previously, we build in a certain level of -- we know we're going to have some winter, both at the tail end of Q4s and first couple of months of the first quarter. So yes, we've seen some cold weather, we have seen some freeze-offs up north, but nothing that I would consider out of the ordinary.

There are no further telephone questions at this time. I'd like to turn the conference back over to Andrew Ziola for any additional or closing remarks.

Okay. Thank you, great questions today. Our quiet period for the first quarter starts when we close our books in April and extends until earnings are released in early May.

Thank you for joining us.

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