Oneok Inc (OKE) — Q4 2016 Earnings Call Transcript

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

Thank you, T.D. Good morning and thank you 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 of 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 Phil May, Natural Gas Pipelines. We also have Kevin Burdick, who is 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 the while improving our consolidated credit metrics. Our integrated assets and growth over the last 10 years have 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.

Thanks, 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 1.03 times for the fourth quarter and 1.09 times for the full year of 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 a trailing 12 months GAAP debt-to-EBITDA ratio of 4.2 times at December 31st. 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 tax as a non-controlling interest 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 segments 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 and construction, we expect to be within the guidance range as this segment delivered nearly $1.1 billion in adjusted EBITDA in 2016. We expect to lower the cost of funding resulting from our strong financial performance - 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 round our target of four times in the next 18 to 24 months. In terms of timing and next steps for the merger transaction, we expect to file a registration statement and joint property 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 estimate 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 liquid 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 mid-year 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 facilities 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 $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 790 million cubic feet per day 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 continued 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 liquid segment which is a take away 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 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 expected 2017 capital expenditures of $170 million to $210 million is dedicated to 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 Road Runner gas transmission pipeline, ONEOK's West Texas 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 begun 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 of 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 revive 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 the 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 of 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 opportunities. 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 with the 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.

Good morning, everyone, and thank you for the update on the narrative. Terry, could you elaborate on the fourth quarter Permian gathering volumes being slightly below the annual average? I was under the impression that weather would not have played a role, so any insights on what occurred there and your expectations for 2017 would be appreciated. Have you provided any additional details beyond what you mentioned in the narrative?

Sure, John. I am going to let Sheridan kind of walk you through those components.

We did notice some weather impact in the Permian, particularly affecting the West Texas pipeline, which experienced more weather-related issues through the Barnett Shale. We also observed increased ethane rejection on the West Texas pipeline in the fourth quarter. Growth in the Permian should continue. Throughout the year, the Permian has remained fairly steady, and we are in the process of connecting two additional plants this year, which will boost our volumes from the Permian.

Okay, that's helpful. And 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're 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, and then would it be fair to say because it's a second half situation that you're going to be closer to the 900 range kind of in the third and fourth quarters? Is that the right way to think about it?

I think to think about it definitely would be ramping up in the second half of the year because that's when we said that we'll start seeing the 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, I think we will start seeing this cross the 800. A lot depends on the growth out of the SCOOP and the STACK. We're seeing a lot of great results today and we are seeing some of those, I mentioned some volume growth out of the Permian, and then the Williston Basin still comes on strong for us as well. We see that throughout the year. So I think, in answer to your question, it is going to be much more second half with your ethane and these plants continue to ramp up, but we will probably cross 800 in the second quarter.

Okay, that's helpful. And just if I could just switch gears on one other area, just I am assuming more of a question for Derek; you're indicating you get us to four times leverage in the next 18 to 24 months or so, and our assumption has been such it's primarily an EBITDA growth story in that regard, not really dependent so much on equity issuance. So if you could just sort of clarify for us how you think you're getting there, that would really be helpful?

Sure, John, this is Derek, and you are exactly right. I think we don't need to issue equity in order to get the leverage metrics down into that target range of four 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. And just last one, just in the deck you provided to us, Terry, there was the optimization, marketing price differential; you indicated there were 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've seen in the third quarter and also the structure of the 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 the spreads between come and go; it would 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. So I think that we will 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.

Afternoon, guys, so just a quick follow up for clarification on John's point, so that 17 millionish that you guys refer you on page eight in the slide deck, did I just get that right that you said that 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 book. We had a very good third quarter in the marketing, but we're definitely seeing wider spreads today than we saw in December as we continue to go through that. So we'll definitely be better off in the first quarter; maybe different within the fourth quarter.

Perfect. So a bigger picture question, you know, there's been a theme of we’re starting new projects, and I know you guys had some delayed projects. You also talked about that 1.4 Bcf type of takeaway capacity out of SCOOP and STACK; can you just remind me how much a pipe like that would cost, what catalysts to watch for on it moving forward in other new projects that you might think about coming back into the queue?

Sure, Kristina, I’ll let Phil take that question.

Sure, Kristina. The pipeline that we're trying to develop out of the SCOOP and STACK is 200-210 miles of 36-inch pipe with compression, and 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.

And 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 that 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 certainly along the lines of the types of projects that Phil’s talking about specifically in the pipeline segment. But 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 a third, a third, and a third; that is a third G&P, the third pipes, and third liquids. And so generally that's how you think about it; that's what the projects look like that are currently under development.

That's really helpful. Lastly, could you remind me of your thoughts on the appetite for strategic M&A, especially after the transaction announced earlier this year, and how you might consider using the currency?

Sure, certainly we have an appetite for M&A; we've got an appetite for asset acquisitions as well and in the things that the transaction certainly provides a benefit to our currency. And we are continually thinking about strategic M&A and what assets that we don't have that would certainly make sense. So, the challenge remains finding something that's actionable and if you do find something actionable trying to find something where the bid has spreads not so wide. So those challenges remain, but certainly as a result of this transaction we’re very interested in acquisition opportunities.

Perfect, thanks guys for the update.

Thank you.

Hey, good morning. Just wanted to follow up on the last question. You think about the guidance numbers, it looks like you're more than buying on fractionation capacity for 2017 and 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, I mean how soon do you think you might need some new fractionation capacity? Do you think about top end being 6.35, 1.40 for ethane; you get the 7.75, and you talked in the past about 100,000 barrels incremental from SCOOP STACK; how soon could that occur and how long will it be time to get some of those things in?

Well, it usually probably takes us about two years to get a frac for that standpoint, and I think we won't need additional frac capacity until we get into 2019. Some of the people we've talked about out of the SCOOP or the STACK we are talking about dish transporting their barrels, maybe not doing a complete frac, complete bundle service. So you kind of play that into as well, but I think it will be 2019 before we would really think we need to look at additional frac capacity.

And 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. If that type of activity continues, we're going to need some additional capacity probably in the next couple of years. So because we will eat up our available capacity pretty quickly. As we think about the Williston, we got a couple hundred million a day of capacity available there. We also have the opportunity for some low-cost expansions, so you're probably looking at maybe three to four years before we would get in with the current type pricing environment where you would fill up our capacity and may need additional processing.

Okay, and then last one real quick. You mentioned the higher rates being somewhat in the G&P somewhat due to some higher IP wells coming on, but I was just curious if you could expand a little. I mean, believe there was a contract settlement with one of the customers in the Bakken, and I was also curious to see if there was any sort of movement on perhaps the Mid-Con and getting any momentum there and maybe getting a little more money there?

Eric, this is Kevin again. The rate increased slightly in the fourth quarter due to an agreement on a sizable restructured contract. Additionally, we saw a significant increase in IP gas during the fourth quarter, which also contributed to the rise in our volumes, with most of that gas associated with contracts that had a higher fee-based structure. Looking ahead, we expect that rate to stabilize in the $0.80 range as additional volumes come in and as the mix of contracts varies. This discussion is distinct from the $8 million settlement regarding a service contract that is not related to our producer or customer contracts.

Okay, alright, well thanks a lot and congrats on your promotion.

Everybody, I want to just make a correction. I guess I got tongue tied in one of my numbers when I was talking about Mid-Continent. Natural gas volumes, I said 790 million cubic feet per day periodically, and 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. So hopefully that clarifies it and we will make sure the transcript appropriately reflects the corrected number. Thank you. Now back to questions.

Hi, thanks. Can you provide an update on where you stand on the West Texas LPG line and then just how that sort of interplays with, sounds like you're connecting some additional plants in the Permian? And do you have enough takeaway capacity? Just kind of you know, update in terms of your thoughts on NGL takeaway capacity and just any update on West Texas LPG?

Sure, this is Sheridan. We have a hearing regarding the West Texas rate case scheduled for the end of March, after which it will proceed through its usual process until we reach a resolution. Concerning the new plants we are connecting, we can secure contracts for these at market rates rather than lower rates, reflecting current market conditions. As we increase our volume, we'll receive it at a higher rate. We are in discussions with various plants, some of which are at different stages, and we believe there is a significant chance of expanding the West Texas pipeline from the Permian Basin as it continues to evolve. The success of these discussions will influence our ability to contract with the new plants anticipated to come online in the next year to 18 months.

Okay, and that expansion, would that be at the other end, like timing, or is that just pumps and cost? I'm 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 in some pumps and a little bit of looping up some of the line, and there probably will be additional gathering infrastructure out to the Permian.

Okay, great. And 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.

Okay. So I feel 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?

Certainly, this will occur over time, and the $200 million EBITDA impact is still a solid figure. The timeline for this impact spans 2017, 2018, and 2019. The cumulative effect of all the additional ethane entering the market will yield an impact of $200 million. That's still valid. So regarding the timing, 2018 is significant for the startup of petrochemical facilities. As mentioned earlier, we have three large crackers coming online that will process between 80,000 to 100,000 barrels of ethane daily each. This is substantial in a market that handles a million barrels of ethane daily. Additionally, we will see more crackers beginning operations in 2018, leading us to anticipate considerable growth in our NGL segment. The continued boost from ethane remains a major part of our narrative, alongside the raw feed growth occurring in the STACK, SCOOP, and Permian regions.

Hey, Terry, thanks for taking my question.

You bet, Chris, how are you?

I am well, thanks. I just want to follow real quickly maybe on where Michael left off. So just to understand, so 40 to 50 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. And so I guess I'm just wondering do you still see sort of the regional profile that you've outlined before where we should expect sort of all Permian to be recovered, and then we move to Mid-Con for the next sort of tranche of recovery?

Yes, Chris, that's correct. The Permian will be addressed first, followed by the Mid-Continent. However, I should mention that the output from the Mid-Continent isn't far behind that of the Permian. They are quite comparable, so it's possible we could see some production from the Mid-Continent earlier, depending on how the power contracts are arranged. Overall, that's the general outlook we have.

Okay. And then there was a question earlier about frac capacity within ONEOK franchise. We've obviously seen some frac announcements now for the first time in a while. And I know that some others at Bellevue remained permanent. 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, you know vis-à-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 and they wanted to fill their frac capacity first. And so that's why we were working with them to just do a transport-only type of deal. In terms of our frac capacity, I would like to see what comes out of the SCOOP and the STACK; there's an opportunity to fill the existing capacity we have today and obviously ethane is going to flow that capacity as well. But we are very excited that we think as we go forward and look into 2019 and beyond that there are opportunities as the Permian grows, as the SCOOP and STACK grows, that we may have a frac coming on but all is going to depend on commitments from the producers and processors I'm going forward.

So, just the only thing I would add to that, Chris, is that from an ethane perspective, we have the capacity necessary to reap this $200 million impact, EBITDA impact from incremental ethane. So that capacity, our deethinizers are underutilized right now as a result of the ethane rejection. So there's no capacity that has any meaningful size and needs to be built to accommodate that. What Sheridan's primarily talked 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 the full menu of services these customers are gathering, fractionation, and certainly storage as well.

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

Okay, I was more curious like if somebody was signing up for new frac capacity, I guess chances are that's under a fairly lengthy commitment, so I was just wondering if then somebody is looking to take pipe capacity on your system to kind of provide the volume that would subsequently be frac if you would get sort of an equal duration contract or how that might work. And I know you've had sort of a Sterling three expansion opportunity out there for a while—like at what point you might maybe see that fall back into reality kind of to Kristina's earlier question?

I think really, as we talk about people that we may be transporting out of the SCOOP and the STACK, they’re predominantly going to be going into their own fracs that they own. They would be doing it, but we negotiate on those transportation deals independently. If they're going to take it to a third-party frac, we negotiate those independently. So we'll go after the length, the term that we think is appropriate for our business here 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, and some of the other volume that we transport only.

Could you clarify something you mentioned earlier regarding the anticipated recovery of C2 volumes? You're suggesting that certain regions in the Mid-Con are competitive with the Permian, indicating that those volumes might recover first, followed by a trend of rising costs. Is that an accurate interpretation? Additionally, you mentioned a bundle fee for the Permian at less than $0.03. Is that the approximate figure for the lowest cost areas in the Mid-Con as well?

No, the $0.03 that we've 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, and that higher rate is where we see is comparable to the Mid-Continent. So if you just look at what we've provided, we've provided $0.08 a gallon on an average fee out of the Mid-Continent. And we feel that fee is competitive with some of the fees that are out of some of the new plants that are out of the Permian that are on the newer pipelines which are at a higher rate than our normal pipelines.

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

The $0.03 is indeed solely for transportation; it represents the average fee for the entire West Texas pipeline, which includes Permian, Barnett Shale, East Texas, and short haul volumes. This fee is averaged across all those areas. Naturally, Permian will have a higher rate even on our system. The $0.08 out in the Mid-Continent is an average fee that includes both transportation and fractionation. It may also apply to various locations, but as you mentioned, certain contracts in the Mid-Continent are competitive with some of the new plants coming from the Permian.

Okay, that's very helpful. Thanks for the clarification.

You bet. Thank you, Chris.

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