歐尼克 (OKE) 2016 Q4 法說會逐字稿

Good day, and welcome to the ONEOK and ONEOK Partners fourth-quarter 2016 earnings call. Today's conference is being recorded.

At this time, I would like to turn the conference over to today's host, Mr. T.D. Eureste. Please go ahead, sir.

Thank you. And welcome to ONEOK and ONEOK Partners fourth-quarter and year-end 2016 earnings conference call.

A reminder that statements made during this call that might include ONEOK or ONEOK Partners expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provisions of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in any forward-looking statements.

For discussion of factors that could cause actual results to differ, please refer to our SEC filings. Our first speaker is Terry Spencer, President and CEO of ONEOK and ONEOK Partners. Terry?

Thank you, T.D. Good morning, and thank you all 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, Strategic Planning and Corporate Affairs; Derek Reiners, Senior Vice President and Chief Financial Officer; and our Senior Vice Presidents, Wes Christensen, Operations; Sheridan Swords, Natural Gas Liquids; and Phill May, Natural Gas Pipelines.

We also have Kevin Burdick, who was recently promoted to Executive Vice President and Chief Commercial Officer, reporting to me, with responsibility for all of our business segment commercial activities. Kevin has served a number of key leadership roles and performed at a high level.

I have no doubt that Kevin's exceptional leadership skills and experience will continue to serve the Company well in his new role. Congratulations to Kevin.

Thank you for joining us this morning to review our 2016 and fourth-quarter results. ONEOK and ONEOK Partners reported strong 2016 financial performance as ONEOK Partners adjusted EBITDA increased nearly 18% compared with 2015.

Increased fee-based earnings drove double-digit adjusted EBITDA growth in all three of our business segments. This strong year-over-year adjusted EBITDA growth was achieved despite increased ethane rejection and severe weather in December that impacted volumes in our Natural Gas Liquids and Natural Gas Gathering and Processing segments in both the Williston Basin and the Mid-Continent.

The impact of the severe weather and increased ethane rejection in December reduced fourth-quarter results by approximately $15 million. Severe weather continued early in the first quarter of 2017, impacting volumes, but volumes have rebounded significantly in February to November 2016 levels, which were some of our highest monthly volumes.

We expect year-over-year adjusted EBITDA growth in 2017 to be weighted towards the back half of the year. This growth is driven by mostly routine, high-return capital expenditures to fill available capacity in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and sets the stage for significant adjusted EBITDA growth into 2018 and beyond.

Growth is expected to be fueled by industry fundamentals from increased producer activity and highly productive basins, across our operating footprint, and from increased ethane demand from the petrochemical industry and NGL exports. We anticipate closing our recently announced acquisition of the remaining 60% of ONEOK Partners that we don't already own in the second quarter of this year.

We expect the transaction to be immediately accretive and then double-digit accretive to ONEOK's distributable cash flow in all years from 2018 through 2021, providing for a 21% initial dividend increase. Followed by expected annual dividend growth of 9% to 11% through 2021, with 1.2 times or greater dividend coverage all while improving our consolidated credit metrics.

Our integrated assets and growth over the last 10 years has us well positioned to capitalize on improving market fundamentals and the continued development of the extensive resource plays within our broad 37,000-mile footprint. Derek will now provide additional details about our financial performance and outlook.

Thank you, Terry. Starting with the Partnership, fourth-quarter and full-year 2016 adjusted EBITDA increased compared with 2015 by approximately $20 million and $275 million, respectively.

ONEOK Partners distribution coverage ratio was 1.3 -- 1.03 times for the fourth quarter and 1.09 times for the full year 2016. A substantial improvement compared with the 0.86 times coverage for the full year 2015.

The slightly lower fourth-quarter distribution coverage ratio, as anticipated, was due to the timing of maintenance capital spending. Credit metrics again improved the Partnership's already strong balance sheet, with the trailing 12 months GAAP debt to EBITDA ratio 4.2 times at December 31.

ONEOK maintained its healthy dividend coverage throughout 2016, ending the full-year coverage of 1.31 times or approximately $250 million of cash on hand and an undrawn $300 million credit facility. We expect to utilize ONEOK's available cash to pay down consolidated debt this year.

ONEOK's 2017 financial guidance was issued as if our proposed merger transaction with ONEOK Partners closed on January 1. We expect to true up the guidance for net income, income taxes and non-controlling interests, once the timing and related impacts of the transaction are known.

We still expect closing to occur in the second quarter. Adjusted EBITDA and distributable cash flow should not be materially impacted by the timing of the transaction closing.

For the NGL segment's 2017 adjusted EBITDA guidance, we are mindful of the primary components that may impact results. Including the timing and amount of additional ethane recovery and incremental volumes from the STACK and SCOOP.

Based upon our current assessment of producer activity in petrochemical construction, we expect to be within the guidance range as this segment delivered nearly $1.1 billion in adjusted EBITDA in 2016. We expect a lower cost of funding resulting from our strong financial performance in 2016 -- our strong financial performance and successful efforts to reduce commodity price risk, combined with the recent transaction announcement, which eliminates incentive distribution rights.

Also, the credit rating agencies have viewed ONEOK favorably, placing ONEOK on review for upgrade to investment grade, following the closing of the transaction. The expected growth in adjusted EBITDA and use of the excess cash on hand to repay debt should enhance ONEOK -- should enable ONEOK to improve its credit metrics. Reducing consolidated debt to EBITDA to around our target of 4 times in the next 18 to 24 months.

In terms of timing and next steps for the merger transaction, we expect to file registration statement and joint proxy statement within the next week or so. Once the registration statement is declared effective by the SEC, we will mail the joint proxy statement to our shareholders and unit holders and set unit holder and shareholder meetings to be held on the same day.

As of now our best estimates is for the transaction to close in June. I'll now hand the call back to Terry.

Thank you, Derek. Let's take a closer look at each of our business segments.

Starting with our Natural Gas Liquids segment, 2016 adjusted EBITDA for the segment increased more than 10% compared with 2015, benefiting from new natural gas processing plant connections in the Williston Basin and STACK and SCOOP areas, and increased ethane recovery during the first half of the year. Severe winter weather continued to impact our system in January; however, NGL gathered volumes have rebounded in February, averaging approximately 780,000 barrels per day this month. This average is more in line with our November 2016 volumes.

We've also seen higher NGL product price differential and location differentials, which we expect will partially offset early year impacts from weather. We expect 2017 NGL volumes to be driven by increased drilling activity across our system and the ramp up and full-year benefit of the six natural gas processing plants we connected in 2016.

We also expect to connect an additional six plants this year, including one in the Rocky Mountain region, three in the Mid-Continent and two in the Permian Basin. These new connections will increase the Partnership's total third-party plant connections to nearly 200. Producers are planning to move more rigs to the STACK and SCOOP area and the Williston Basin by midyear, and with the ramp up of new processing plants, we expect volumes to increase significantly during the back half of 2017.

With respect to ethane, we continue to expect ethane recovery levels to fluctuate throughout 2017. But we are also seeing positive signs from petrochemical and export facility so far this year. At least three world-scale petrochemical facilities are slated to begin operations in the second half of 2017. In addition to increased capacity utilization at new export facilities.

Additionally, a new 36,000 barrel per day Gulf Coast ethane cracker recently began start up operations. While ethane recovery is an important part of our growth outlook and is expected to provide additional NGL volume growth into 2018, it's important to note that our 2017 financial guidance expects increased recovery of ethane to provide $40 million to $60 million of adjusted EBITDA growth.

Moving on to the Natural Gas Gathering and Processing segment, 2016 adjusted EBITDA increased 40% compared with 2015. Driven by higher average fee rates and continued volume growth in the Williston Basin. Prior to December's severe weather impacts, natural gas volumes processed in the Williston Basin exceeded 780 million cubic feet per day in November.

The segment's average fee rate increased to $0.84 per MMBTU in the fourth quarter 2016 and $0.76 per MMBTU for the full year. High initial production volumes from customers with fee-based contracts contributed to the higher average fee rate in the fourth quarter. We expect an average fee rate of closer to the $0.80 in 2017, with fluctuations due to volume and contract mix. Plus, we have hedged a significant portion of the segment's remaining 2017 commodity price exposure.

In the Mid-Continent, we saw several additional multi-well pad completions through the end of 2016, and into early 2017. Our natural gas volumes processed increased in the fourth quarter, compared with the third quarter, and we saw processed volumes exceed [690 million cubic feet per day] (corrected by company after the call) periodically during the fourth quarter.

Producers across our Natural Gas Gathering and Processing systems have accelerated their drilling activity, particularly in the prolific STACK and SCOOP plays where production results continue to improve. We currently have 10 to 12 rigs on our dedicated acreage in the STACK and SCOOP, compared with 3 to 4 rigs at the low point in 2016.

Recently, a number of our gathering and processing customers, which account for more than 200,000 acres of dedication, have increased their drilling programs which could push rigs on our acreage to a range of 17 to 20 by the end of 2017. Volumes are expected to increase significantly in the second half of 2017 as producers continue to move additional rigs into the area during the first half of the year.

The increased drilling activity in the STACK and SCOOP not only benefits our Natural Gas Gathering and Processing segment but also significantly benefits our Natural Gas Liquids segment, which is a takeaway service provider in Oklahoma as is our Natural Gas Pipeline segment.

Producers have also accelerated drilling and completion activity in the Williston Basin, with expectations for higher 2017 volumes compared with 2016. Producers continue moving rigs back into the core of the basin with approximately 25 correction -- 23 to 25 rigs currently on our dedicated acreage.

Approximately 300 drilled but uncompleted wells remain on ONEOK's acreage dedications, which provide a backlog of volume growth opportunities in 2017 requiring minimal capital while rigs continue to increase throughout the year. We expect to connect approximately 400 wells in the Williston Basin this year, compared to nearly 340 in 2016.

The segment remains well positioned to take advantage of growth opportunities requiring minimal capital investments such as well connections and compression projects. The majority of the segment's $170 million to $210 million of expected 2017 capital expenditures, is dedicated for these types of high-return projects.

In the Natural Gas Pipeline segment, 2016 adjusted EBITDA increased 14% compared with 2015. The segment continues to benefit from higher fee-based earnings driven by increased firm contracted capacity and capital growth projects recently placed in service.

In 2017, the segment is expected to benefit from a full year of operations on three natural gas transportation projects placed in service last year, including the Roadrunner Gas Transmission Pipeline, ONEOK West Tex Pipeline expansion and the Midwestern Gas Transmission expansion. Combined, these three projects added an additional 1 billion cubic feet per day of transportation capacity to ONEOK's Natural Gas Pipelines system.

All three projects are fully subscribed under long-term, firm, fee-based commitments. The segment continues to expand its operations this year with additional capital growth projects, including additional electric generation plant connections and increasing natural gas takeaway capacity out of prolific shale plays, such as the STACK and SCOOP.

Already this year, we've began construction on a 25-mile pipeline that will provide transportation and storage services to OG&E's Mustang electric generation plant near Oklahoma City. This project is supported by a long-term, fee-based agreement with OG&E.

We've also started construction on a westbound expansion of our ONEOK gas transmission pipeline out of the STACK play. This project is also supported by a long-term firm commitment. The initial expansion design, which consists of adding compression, provides for 100 million cubic feet per day of capacity on the pipeline and is scalable up to 400 million cubic feet per day. Discussions are ongoing with producers which could potentially increase the expansion volume.

We expect to complete the Mustang project in the third quarter this year and complete the westbound expansion in the second quarter of 2018. In addition, we continue our discussions with producers for ONEOK to potentially construct a new natural gas pipeline to provide much needed takeaway services from the STACK and SCOOP plays.

If ONEOK is successful in securing the necessary contractual commitments and Board approvals, the proposed 200-mile intrastate pipeline and related compression would run through the middle of the STACK and SCOOP. Providing essential takeaway of up to 1.4 billion cubic feet per day and connectivity with existing ONEOK facilities in central Oklahoma, as well as the Bennington market hub in southeastern Oklahoma.

If constructed, the pipeline and related infrastructure would have an anticipated completion date of the third-quarter 2018. Our Natural Gas Pipeline segment is well positioned in increasingly active basins such as the Delaware and Midland Basins and the STACK and SCOOP plays, to compete for additional takeaway opportunities.

Looking ahead to the remainder of 2017 and beyond, we are well positioned for growth opportunity. The continued improvements in producer drilling economics, funding costs and a long runway of future development potential in our basins, are resulting in more customers needing increased takeaway capacity.

With this line of sight into growth opportunities and improving market fundamentals, we have between $1.5 billion and $2.5 billion of future potential organic growth projects in the development phase. Additionally, we have lowered our cost of funding to support these growth opportunities with the recently announced transaction.

We are confident in our assets, experienced people, financial flexibility and discipline and our legacy of providing reliable and quality service to our customers and creating value for our stakeholders, even during difficult industry cycles. 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, reliably and in an environmentally responsible manner.

Operator, we're now ready to take questions.

Thank you.

(Operator Instructions)

John Edwards, Credit Suisse.

Good morning, everybody. Thanks for updating us with the narrative.

Just as a follow-up, Terry. Could you just walk us through -- the fourth-quarter Permian gather volumes were a little bit below average for the year. I was just thinking that wasn't going to be a weather impact there. So any color of what happened there?

Then, how you think that will turn up in 2017, a little bit beyond the detail you provided in the narrative already?

Sure, John. I'm going to let Sheridan walk you through those components.

First thing, John, we did see a little bit of impact of weather in the Permian. But West Texas Pipeline, which a lot of people think of as just the Permian, did see more weather impact through the Barnett Shale. We did see some methane, more increased ethane rejection, out of on the West Texas pipeline in the fourth quarter.

We continue to see growth in the Permian. As we go in, the Permian has been fairly steady through the year. But we are connecting additional plants in the Permian. Two additional plants this year will increase our volumes out of the Permian.

Okay, that's helpful.

Then just as far as ramping up to the overall guidance of 800 to 900 that you provided a few weeks back. I think you indicated in your opening comments you are already seeing in February something like 780. So would it be fair to say that you're thinking you'll cross over -- I mean when would you expect to cross north of 800?

Then would it be fair to say because it is a second-half situation, that you're going to be closer to the 900 range in the third and fourth quarters? Is that the right way to think about it?

I think the thing to think about is we will definitely be ramping up in the second half of the year because that is when we've said that we will start seeing that ethane sustainably coming out in the second part of the year, as we go forward.

But I think, as we come into the second quarter is when we'll start seeing this cross the 800. A lot depends on the growth out of the SCOOP and the STACK. We are seeing a lot of great results today. We are seeing, as I mentioned, some volume growth out of the Permian. Then the Williston Basin still comes on strong for us as well. We see that throughout the year.

I think in answer to your question, it's going to be much more second half with your ethane, and these plants continue to ramp up. We will probably cross 800 in the second quarter.

Okay, that's helpful. If I could just switch gears on one other area.

I'm assuming more of a question for Derek. You're indicating, get to four times leverage in the next 18 to 24 months or so. Our assumption has been primarily an EBITDA growth story in that regard, not really dependent so much on equity issuance. If you could just clarify for us how you think you're getting there, that would really be helpful.

Sure, John, this is Derek.

You're exactly right. I think we don't need to issue equity in order to get the leverage metrics down into that target range of 4 times. Now, certainly we could, depending on additional capital projects. If we have some large capital projects, we could issue some equity there. But really don't have the need to do so in that 18 to 24 months, as we're thinking about it today.

Okay that's helpful. Last one.

In the deck you provided to us, Terry, there was the optimization marketing price differential. You indicated there was some squeezing going on there. How should we be thinking about that going forward?

John, definitely in the fourth quarter, the spreads were narrower than we have seen in the third quarter. Also, the structures of market that we get a lot of our marketing activity was narrower than we've seen. But as we move into the first quarter, we've already seen spreads between Conway and Belvieu be a lot wider than in previous years.

We're seeing propane at $0.08 to $0.10, and butane at $0.12 in February and a little bit narrowing in March but still very strong. I think that we'll have a very good optimization in the first quarter.

Okay, that's it for me. Thank you so much for the clarifications.

Thank you, John.

Kristina Kazarian, Deutsche Bank.

Afternoon, guys. Just a quick follow-up for clarification on John's point.

That $17 million-ish that you guys refer on page 8 in the slide deck. Did I just get that right that you said that's already worked itself out and probably won't be a go-forward impact that we should be thinking about?

The $17 million is compared to the third-quarter, and most of that is in the marketing. But we had a very good third quarter in the marketing. But we're definitely seeing wider spreads today then we saw in December as we continue to go through that.

So we definitely should be better off in the first quarter than we definitely were in the fourth quarter.

Perfect. A bigger picture question.

There's been a theme of we're starting new projects. I know you guys had some delayed projects. You also talked about that 1.4 Bcf pipe takeaway capacity out of SCOOP and STACK. Can you just remind me how much a pipe like that would cost? What the catalysts to watch for on it moving forward, and other new projects that you might think about coming back into the queue?

Sure, Kristina, we'll let Phill take that question.

Sure, Kristina.

The pipeline that we're trying to develop out of the SCOOP and STACK is 210 miles of 36-inch pipe with compression. Depending on what kind of capacity sales that we are able to garner in the discussions, it can be between $750 million and $900 million.

Then other projects that you guys might think about moving back into the queue? Maybe some of the ones that had been delayed before the cycle turned down or anything else on your radar there?

Yes, Kristina, I think you're thinking about it right. As we think about this $1.5 billion to $2.5 billion of projects under development, there's a pretty good portion of it in our gathering and processing segment, where we're adding additional capacity. More around the SCOOP play, and then in certainly along the lines of the types of projects that Phill is talking about specifically in the Pipeline segment. Then also opportunities in the Permian, NGL-related infrastructure, NGL storage, those types of things.

When you think about how it's broken up at a $2.5 billion level, you're roughly talking about one-third, one-third and one-third: one-third G&P, one-third pipes, and one-third liquids. So generally, that's what the projects look like that are currently under development.

That's really helpful. Last one for me, and I know you guys get this a lot.

Can you just remind me of your thoughts, especially post the transaction we announced earlier this year, of appetite for strategic M&A, and how you might think about using the currency?

Sure. Certainly we have an appetite for M&A. We've got an appetite for asset acquisitions as well, and the transaction certainly provides a benefit to our currency.

We're continually thinking about strategic M&A and what assets that we don't have that would certainly makes sense. The challenge remains finding something that's actionable. Then if you do find something actionable, trying to find something where the bid/ask spread is not so wide.

Those challenges remain, but certainly as a result of this transaction, we're very interested in acquisition opportunities.

Perfect. Thanks, guys, for the update.

You bet. Thank you.

Eric Genco, Citi.

Hey, just wanted to follow up on some of the last questions. You think about the guidance numbers. It looks like you're more than fine on fractionation capacity for 2017 maybe into 2018. But if we were to look out a little bit and think about some of the higher end of guidance and how some of that could go, how soon do you think you might need some new fractionation capacity? If you think about top end being 635, 140 for ethane, you get the 775.

You've talked in the past about 100,000 barrels incremental from SCOOP/STACK. How soon could that occur, and how long of a lead time do you need to get some of those things in?

Usually it will probably take us about two years to get a frack in from that standpoint. We won't need additional frac capacity until we get into 2019. Some of the people we've talked about out of the SCOOP and the STACK, we are talking about just transporting their barrels, maybe not doing a complete frac, doing a complete bundle service. You've got to play that into it as well. But I think we'll be into 2019 before we would really think we would need to look at additional frac capacity.

Okay, how about on the processing side?

Eric, on the processing side, again, a lot of it will depend on the ramp that we see. As Terry mentioned, we have seen pretty significant uptick in rigs in the STACK. That area, those wells are much higher volume than we see in the Bakken. So if that type of activity continues, we're going to need some additional capacity, probably in the next couple of years. Because we'll eat up our available capacity pretty quickly.

As we think about the Williston, we've got a couple 100 million a day of capacity available there. We also have the opportunity for some low-cost expansions. You're probably looking at maybe three to four years before we would get in with current type pricing environment, where you would fill up our capacity and may need additional processing.

Last one real quick. You mentioned the higher rates in the G&P segment being somewhat due to some higher IP wells coming on. I was just curious if you could expand a little. I believe there was a contract settlement, one of the customers in the Bakken.

I was also curious to see if there is any sort of movement on perhaps the Mid-Continent in getting any momentum there and may be getting a little more money there?

Eric, this is Kevin again.

That rate did spike a little bit in the fourth quarter. We did reach agreement on a restructured contract that was relatively sizable that drove that up a little bit. But we also had a significant amount of IP gas come on in the fourth quarter, which did drive up our volumes. The vast majority of that gas was on contracts that had a much higher fee-based component.

So quarter to quarter, we think that rate will settle in more of the $0.80 range as other volume comes on and just the volume mix on the contracts moves around a little bit. Now, the $8 million contract settlement was a service contract that is unrelated to our producer, our customer contracts.

Thanks a lot and congrats on your promotion.

Everybody, I wanted just to make just a quick correction. I guess I got tongue-tied on one of my numbers when I was talking about Mid-Continent natural gas lines. I said 790 million cubic feet per day periodically. What I meant to say was 690 million cubic feet per day. So perhaps that was wishful thinking on my part. But anyway, my apologies.

Hopefully that clarifies it, and we'll make sure the transcript appropriately reflects the corrected number. Thank you. Now back to questions.

Michael Blum, Wells Fargo.

Hi, thanks. Can you provide an update on where you stand on the West Texas LPG line and just how that interplay's with -- it sounds like you're connecting some additional plants in the Permian. Do you have enough take away capacity? Just kind of an update in terms of your thoughts on NGL take away capacity and just any update on West Texas LPG?

Michael, this is Sheridan.

On the West Texas rate case, we have a hearing in front of an Administrative Law Judge at the end of March. Then after that, it will go through its normal course to come to a resolution on that.

In terms of how that impacts the new plants we are connecting, we are able to contract these new plants at market rates, not at the lower rates, due to that is what the market is out there. So as we increase volume out there, we'll get it at a higher rate.

The capacity that we have is, we're talking to many different plants out there, some much further than others. We think that through those discussions, there is a distinct possibility of an expansion coming on the West Texas pipeline out of the Permian Basin as that continues to grow. That will be depending on how successful we are with contracting some of these new plants that will be up in the next year to 18 months.

Okay, and that expansion, any idea there on timing; or is that just pumps and costs? Just trying to get a feel for what that would entail.

Well, definitely it will be cheaper than laying a new line. But it will be some pumps and a little bit of looping of some of the line. There will probably be some additional gathering infrastructure out to the Permian.

Okay. Great.

Then the other question. Terry, I think I heard you say earlier that in the 2017 guidance assumes $40 million to $60 million EBITDA uplift from ethane recovery? Did I hear that right?

That's correct.

I think it was about a year ago, you guys were talking about the potential for $200 million EBITDA uplift from ethane recovery? When do you think that could occur?

Well, certainly that happens over time. That $200 million EBITDA impact, that's still a good number. The timing is the 2017, 2018 and 2019 impacts. The cumulative effect of all the incremental ethane coming on would have an impact of $200 million. So that all still works. That's the timing.

2018 is a big year for the petrochemical facilities starting up. As we said earlier in the call, we've got three large crackers coming on that are going to crack anywhere from 80,000 barrels to 100,000 barrels a day apiece of ethane. So of course that is pretty big in a million-barrel-a-day ethane market. Then we have even significantly more crackers starting up in the 2018 timeframe.

So we expect significant uplift in this business as we think forward in this NGL segment. The uplift from ethane continues to be a big part of our story, in addition to all the raw feed growth that is happening in the STACK and the SCOOP and in the Permian.

Great. Thank you very much.

(Operator Instructions)

Chris Sighinolfi, Jefferies

Terry, thanks for taking my question.

You bet, Chris. How are you?

I'm well. I'm well, thanks.

I just wanted follow up real quickly maybe on where Michael left off just to understand. $40 million to $60 million is what's in the guidance for this year. Sheridan, I think, was mentioning you're still anticipating that to be mostly back-half loaded.

I'm just wondering, do you still see the regional profile that you've outlined before? Where we should expect all Permian to be recovered, and then we move to Mid-Con for the next tranche of recovery?

Yes. Chris, that is right. The Permian will come first, and then we'll go into the Mid-Continent. I will say that the rates out of the Mid-Continent aren't very far behind the Permian. They are very close to each other.

So you could see a little bit come out of Mid-Continent first, depending on how our contracts are structured. But basically, on a high level, that's what we see happening.

Okay. There was a question earlier about frac capacity within the ONEOK franchise. We've obviously seen some frac announcements now, first time in a while. I know that some others at Belvieu remain permitted.

You had mentioned, Sheridan, potential for you to transport volumes on behalf of potentially what others might frac. Can you just talk to us a little bit about that dynamic and how you think it might take shape? Vis-a-vis the producer schedules and then also this recovery dynamic?

Well, in terms of just transporting out of the SCOOP and the STACK, we have some customers out of the SCOOP and the STACK that have frac capacity. They want to fill their frac capacity first. So that is why we are working with them to just do a transport-only type deal.

In terms of our frac capacity, we'll just have to see what comes out of the SCOOP and the STACK. There is an opportunity to fill the existing capacity we have today. Obviously, ethane is going to fill the capacity as well.

But we are very excited. We think as we go forward and look into 2019 and beyond, that there is opportunities as the Permian grows, as the SCOOP and STACK grows, that we may have fracking. But all that is going to depend on commitments from the producers and processors going forward.

The only thing I would add to that, Chris, is from an ethane perspective, we have the capacity necessary to reap this $200 million EBITDA impact from incremental ethane. That capacity, our de-ethanizors are underutilized right now as a result of the ethane rejection. So there's no capacity of any meaningful size that needs to be built to accommodate that.

What Sheridan is primarily talking about is the raw feed or C3-plus capacity that needs to be constructed to accommodate this organic growth. Not just out of the STACK and the SCOOP, but certainly out of the Permian. We expect to be a fractionation service provider for customers in the Permian, even though currently many of our customers frac in other locations.

As we bring on the incremental development that's happening in the Permian, we expect to be providing a full menu of services to these customers, gathering fractionation and certainly storage as well.

The only other thing I would add to that, is that we as well, also have fracs permitted in Mont Belvieu. So when we get the commitments, we will be able to start building fracs.

Okay. I was more curious. Like if somebody who is signing up for new frac capacity, I guess chances are that's under a fairly lengthy commitment. I was just wondering if then somebody is looking to take pipe capacity on your system to provide the volume that would subsequently be fracked, if you would get an equal duration contract or how that might work?

I know you've had a Sterling pre-expansion opportunity out there for a while. At what point you might maybe see that fall back into reality, tying to Kristina's earlier question?

I think really as we talked about people that we may be transporting out of the SCOOP and the STACK, they would predominately be going into their own fracs that they own. They would be doing it. So we negotiate on those transportation deals independently.

If they are going to take it to a third-party frac, we negotiate those independently. We will go after the length of term that we think is appropriate for our business, regardless of what they get on the frac side. Some people have done shorter-term frac deals; some people have done longer-term frac deals on some of the other volume that we transport only.

Okay, if I could really quickly, Sheridan, just to clarify something you had said earlier in response to a question. If I think about the profile of where you're anticipating C2 volumes to be recovered. You have this profile of cost structure, if you will.

What you were saying, if I heard you correctly, some regions within the Mid-Con are competitive relative to the Permian. We would see that volume hit first, and then we profile in a rising cost water flow. Is that the right way to think about it?

Then you'd noted a bundle fee in the Permian of like less than $0.03. I mean, that's kind of the ballpark you're talking about then in terms of the lowest-cost areas of the Mid-Con?

No. The $0.03 that we have talked about is an overall fee on the West Texas Pipeline at the lower rates that we are at today. Most of the other pipelines are at a much higher rate. That higher rate is comparable to the Mid-Continent.

So if you just look at what we provided, we provided $0.08 a gallon on an average fee out of the Mid-Continent. So we feel that fee is competitive with some the new fees that are out of some of the new plants that are out of the Permian that are on the newer pipelines, which are the higher rates than on our pipelines.

Sheridan, the rates $0.03 and the $0.09 that you're referring to are transportation only. They do not include fractionation, correct?

The $0.03, yes, is definitely transportation only; and it is an average fee for the whole West Texas Pipeline. That takes in Permian, Barnett Shale, East Texas, short-haul volume. So it's an average across that whole thing. Obviously, Permian is going to be on the higher seat, even on our system.

The $0.08, now, on the Mid-Continent is an average fee that has both transportation and transportation and frac. But that could also go to Conway, could go to Belvieu, different places. But we see, as you talked about, certain contracts in the Mid-Continent we know are competitive with some of the new plants out of the Permian.

Okay. That's very helpful. Thanks for the clarification.

You bet. Thank you, Chris.

As it appears there are no further questions at this time, I'd now like to turn the conference back over to our presenters for any additional or closing remarks.

Thank you. Our quiet period for the first quarter starts when we close our books in early April and extends until earnings are released after the market closes in early May. Thank you for joining us.

That does conclude today's presentation. Thank you for your participation. You may now disconnect.