Good day. Welcome to the first quarter 2018 ONEOK earnings call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.
Thank you, Mindy. Good morning. Welcome to ONEOK's first quarter 2018 earnings conference call. This call is being webcast live. A replay will be made available. 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 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 CEO of ONEOK. Terry?
Thanks, Andrew. Good morning. 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, and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas Liquids, and Chuck Kelley, Senior Vice President, Natural Gas. On this call, we will focus on our first quarter financial results and operating performance and provide our perspective about the recent FERC announcements related to natural gas and NGL pipelines. Before we dive in, I'd like to start where we left off on our fourth quarter call, which is our $4 billion-plus of announced organic growth projects.
As you may recall, I was clear that the next couple of years will be about executing on these growth projects. We're making good progress so far. On the natural gas liquid side, we continue to work with landowners, state and local agencies, and other stakeholders along the pipeline routes for Elk Creek and Arbuckle II. We expect to begin construction later this year on both projects. Within the last couple of weeks, pipe for Elk Creek started being delivered, a big step closer to actual construction. We plan to start construction with the southern part of Elk Creek first in the third quarter, as this section would allow barrels from the Powder River Basin to flow on Elk Creek before the entire line is complete, which would free up capacity on the Bakken NGL Pipeline for additional barrels from the Williston Basin.
The southern section would be in service as early as the third quarter of 2019. Additionally, our MB4 fractionator is permitted, and we expect construction to begin this month. On the natural gas gathering and processing side, expansions of our Canadian Valley and Bear Creek plants and construction of the Demicks Lake plant are progressing on schedule. Kevin will discuss these projects in more detail shortly. Increased ethane recovery and Mid-Continent volume growth remain key drivers of our 2018 guidance. So far this year, we've seen both. STACK and SCOOP volumes on our system continue to meet or exceed our expectations, and demand for ethane continues to ramp up with additional ethane crackers coming online this quarter. With that, I will now turn the call over to Walt.
Thank you, Terry. ONEOK's first quarter operating income totaled nearly $420 million, a 30% increase year-over-year, and a 6% increase compared with the fourth quarter 2017. First quarter adjusted EBITDA was $570 million, a 24% increase year-over-year, and a 4% increase compared with the fourth quarter 2017. During the first quarter, we paid a dividend of $0.77 per share, and in April, we announced another 3% increase to $0.795 per share, or $3.18 per share on an annualized basis, which is payable on May 15th. We generated more than $115 million of distributable cash flow in excess of our dividends paid in the first quarter. Total distributable cash flow in the quarter was more than $430 million, with healthy dividend coverage of nearly 1.4 times.
In January, we successfully completed a $1.2 billion equity offering, pre-funding a significant portion of our more than $4 billion capital growth program. At March 31, our debt to EBITDA on a trailing 12-month basis was 3.8 times. On an annualized run rate basis, we are at 3.5 times. As we said previously, we expect our leverage to increase modestly as we move through the construction cycle on the larger capital growth projects we've announced this year. We continue to view leverage of four times or less as an important target for ONEOK over the long term. We expect to fund our capital growth projects through excess cash flow from operations and ample borrowing capacity while maintaining our strong credit metrics. We ended the second quarter with no outstanding commercial paper and nearly the full $2.5 billion available on our credit facility.
Since December 31st, we've decreased total debt outstanding by $1 billion. ONEOK's strong liquidity offers us financial flexibility and the ability to repay current debt maturities with cash from operations and short-term debt, or to opportunistically access the long-term debt markets. We are maintaining our financial guidance expectations for 2018 and continue to expect no need to issue equity in 2018 and well into 2019, if at all. Before I turn the call over to Kevin for an operational update, let's briefly discuss the March FERC announcement and the potential impact to ONEOK. First, related to interstate natural gas transportation pipelines, which represent only slightly more than 5% of our total 2018 adjusted EBITDA. A couple of key points. Most of ONEOK's natural gas pipeline demand charge contracts have been established through shipper-specific negotiated rates and settlements and are not based on cost of service calculations.
Additionally, as a corporation, ONEOK is a taxable entity, so any tax allowance adjustments on cost of service rates would reflect an adjustment to the newer, lower corporate tax rate, not an elimination of the tax allowance. From a regulatory timeline perspective, we do have a couple of interstate pipelines with upcoming rate cases, including Viking, which is required as part of its previously negotiated rate settlement to put in place new rates by January 2020. Midwestern is currently undergoing a routine FERC-initiated Section 5 rate review, with any changes in rates being prospective only. Guardian has negotiated rates for virtually all of its firm capacity through 2022. Northern Border Pipeline recently implemented new FERC-approved settlement rates. We do not expect the ultimate outcome of any of these matters to materially impact our financial results. Moving on to FERC-regulated natural gas liquids pipelines.
There is still quite a bit of uncertainty as to how changes related to tax policy may be applied or what adjustments may be made related to indexing during FERC's next five-year review. We've taken a close look at our NGL pipelines that could potentially see some impact from indexing adjustments. A key item to understand about ONEOK is that the vast majority of volumes transported on our NGL pipelines are at negotiated rates, which we expect would see very little impact from a change in indexing. We expect that a 100-basis-point change to the FERC index rate would have an annualized impact to ONEOK's revenue of less than $2.5 million. We feel this hypothetical provides a good look at what could happen in a downside scenario, and we expect the impact would be immaterial.
I'll now turn the call over to Kevin for a closer look at each of our business segments.
Thank you, Walt. Starting with the performance of our Natural Gas Liquids Segment. First quarter adjusted EBITDA increased 23% year-over-year and 11% compared with the fourth quarter 2017. NGL volumes gathered in the first quarter averaged 855,000 barrels per day, a 12% increase compared with the first quarter 2017 volumes, and relatively flat compared with the fourth quarter 2017. Year-over-year growth was primarily driven by increased volumes in the STACK and SCOOP areas of the Midcontinent, a trend that we expect to continue throughout 2018. Winter weather impacted first quarter volumes relative to the fourth quarter, but we've seen since volumes pick up in April. Volumes on our West Texas LPG system reached more than 200,000 barrels per day on several occasions in April, and system-wide NGL gathered volumes reached more than 900,000 barrels per day on multiple days during the month.
NGL volumes in the Mid-Continent are materializing at or above our expectations at this point in the year, driven by strong producer results in the STACK and the SCOOP. In the Williston Basin, our Bakken NGL Pipeline remains full, and we continue to expect to begin transporting additional NGL volumes by rail in the second quarter 2018 to provide interim takeaway capacity until Elk Creek is in service. NGL volumes fractionated averaged more than 690,000 barrels per day during the first quarter, a 21% increase compared with the same period last year, and a 2% increase compared with last quarter. ethane volumes on our system have increased approximately 50,000 barrels per day in the first quarter 2018 compared with the same period in 2017. Our reported ethane rejection levels may look relatively unchanged year-over-year.
This comparison is affected by our 12% increase in NGL volumes gathered since the first quarter 2017. A portion of this increased volume is attributable to ethane recovery. We're seeing increased demand from newly operational petrochemical facilities and exports, and we expect demand to continue to ramp up through the remainder of the year, as recently completed crackers operate at full rates and additional facilities are completed later in the year. Higher optimization and marketing activities in the first quarter also contributed to the segment's adjusted EBITDA increases, resulting in approximately $25 million increases, both year-over-year and sequential quarter-over-quarter. Wider NGL location price differentials between Conway and Mont Belvieu and the sale of NGL inventory previously held contributed to the increases.
We expect wider spreads between Conway and Mont Belvieu to continue until Arbuckle II goes into service as growing volumes from new production consume available transportation capacity between the two market centers. Moving on to the natural gas gathering and processing segment. Adjusted EBITDA for the segment increased 26% year-over-year, driven by volume growth in the Williston Basin and the STACK and SCOOP areas. Adjusted EBITDA decreased approximately 9% compared with the fourth quarter 2017, due primarily to higher third-party processing costs, weather impacts in both of our regions, and temporary system constraints in Oklahoma due to the volume growth. These higher weather-related costs were isolated and are not expected to continue. A key metric for the quarter was our volume growth.
Average natural gas volumes processed in the first quarter 2018 were more than 1.7 billion cubic feet per day, a 24% increase compared with the first quarter 2017, and a 3% increase compared with the fourth quarter 2017. Volume growth compared with the fourth quarter was primarily driven by increased STACK and SCOOP volumes where processed volume averaged 845 million cubic feet per day during the quarter, a more than 6% increase from the fourth quarter, and our highest volumes processed to date in the Mid-Continent. We connected 112 wells in the Williston Basin and 35 wells in the Mid-Continent during the first quarter. We continue to expect approximately 650 total well connections in 2018.
We have approximately 75 million cubic feet per day of available processing capacity in Oklahoma, including the 200 million cubic feet per day offload that is fully in service, and we will add an additional 200 million cubic feet per day of capacity in the fourth quarter 2018 with the completion of our Canadian Valley plant expansion. Available processing capacity in the Williston Basin is approximately 125 million cubic feet per day currently, but this will be reduced with the return of warmer weather and additional well connections. We're in the process of expanding our Bear Creek plant and related infrastructure and expect the initial expansion to 130 million cubic feet per day from 80 million cubic feet per day to be complete in the third quarter of 2018. This expansion will require no additional capital at the plant and minimal capital for additional field compression.
Our 200 million cubic feet per day Demicks Lake plant is expected to be completed in the fourth quarter 2019. In the natural gas pipeline segment, first quarter adjusted EBITDA increased 13% year-over-year and 6% compared with the fourth quarter 2017, primarily benefiting from higher interruptible transportation volumes and increased storage services. The segment this month completed its 100 million cubic feet per day westbound expansion of our ONEOK Gas Transportation system, and we continue to have discussions with producers in the Permian Basin and STACK and SCOOP areas to accommodate additional natural gas takeaway capacity, given the strong growth expectations in those plays. As for the general market conditions, producer activity across our operating footprint remains strong.
In the Williston Basin, our customers continue to experience production increases resulting from drilling and completion improvements, which is causing more of the play to have strong economics, specifically further south and west in McKenzie County and further north in Williams County. ONEOK has substantial acreage dedications in both of these counties. In the STACK and SCOOP areas, it's a similar story. Producers continue to test various drilling and completion techniques in different formations to determine what provides the best results. The volumes we're seeing on our system so far this year from the STACK and SCOOP areas are extremely positive and have met or exceeded our expectations at this point. This continued activity gives us confidence in our volume growth outlook across our operations.
Terry already touched on our growth projects and construction progress, in addition, we continue active discussions with producers and processors for additional commitments on our announced projects. We've contracted an additional 40,000 barrels per day on Arbuckle II, a 20% increase in contracted volumes since the project was announced in February. We've also seen a 20% increase of committed volumes on Elk Creek since it was announced, with more than 120,000 barrels per day now contracted. Terry, that concludes my remarks.
Thanks, Kevin, for that really good and thorough update. Before we take your questions, I think it's important to mention the Western Oklahoma wildfires. Although the fires had a minimal impact to our facilities, the fires did affect and cause hardship for several of our employees. Some employees experienced significant damage to their homes, buildings, or to their farm and ranch lands. Fortunately, last week, rainfall soaked the region and helped firefighters contain the wildfires, which have charred almost 550 sq mi. I want them to know that we are thinking about them as they recover and rebuild. Much work lies ahead for those impacted by the fires, ONEOK is here to help by making resources available to those employees in need of assistance.
To our investors, thank you for your continued support of ONEOK. As always, thank you to our employees for your hard work and continued dedication to operating our assets safely and environmentally responsibly. With that, operator, we're now ready for questions.
Thank you. If you'd like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll go first to Eric Genco with Citi.
Morning, guys.
Morning, Eric.
You've talked in the past about MidCont processing. Each 200 a day plant produces roughly 20,000-25,000 barrels a day of NGLs. Can you just remind me what's a decent rule of thumb for the back end, even if we were to assume full ethane rejection?
Eric, it's Kevin. If you assume full ethane rejection, you're probably talking in that same range.
I'm just trying to think about this now. I was looking back a year ago, the Bakken pipeline was basically full a year ago. If you look at the statewide data February to February, year-over-year, it's almost a 400 a day increase, MCFD a day increase. Basically, the simple math of that would suggest that there's another 50,000 barrels a day. I'm just trying to put this into context. If you need to get to 100,000 a day on Elk Creek, are you basically with what must be being railed out of the basin now, are you basically halfway there to hit your targeted returns?
Well, first, we're not railing today. The pipeline's been able to run a little above name plate.
That's out there. The numbers last year did have some additional, if you remember, it had some additional ethane included in those barrels for our spec due to specification issues downstream.
We've since been able to back some of that ethane out and replace it with C3+ as we've had other additional ethane come on from other parts that are flowing into the Midcontinent frack assets. Where you're going with as we continue to rail, and you look at the available capacity we've got, and you look at the Demicks Lake plant that we'll be adding, the Bear Creek expansion, yeah, if you start doing the math on that, we're a long way down the road as those assets fill up to meet the commitments and to meet the numbers we've provided for Elk Creek.
Okay. That's really helpful.
Yeah.
I guess maybe switching a bit, I just want to ask, I know you get asked the question fairly regularly, around ethane and NGL exports more broadly. If you look at your asset portfolio, you're probably the largest player without an export terminal in-house, recognizing that your molecules can still get to docks today, it's still a potential margin opportunity. How aggressively would you be pursuing another export terminal? We saw another player announce a JV. Someone kind of came in on an ethane terminal. Is that something you're after or could be there? What would be a structure for that that might be interesting over time?
Yeah, Eric, this is Terry. We've been thinking about exports for many years, we've been very actively engaged in developing opportunities. We came real close a few years ago with an opportunity that would've involved a third-party JV partner. It didn't materialize as the economics eroded significantly. We continue to work the export side. Most likely, if we did put an export project together, it probably would involve a potential JV. It could involve existing facilities that are already in place that need to be modified, it could consist of just a completely grassroots new facility. We do and continue to remain very interested in having export capability. It's not absolutely essential that we have it because we have international relationships in markets and market access today.
To your point, it's a good solid fee-based business that would be a nice bolt-on adder to our service capability. Yeah, we continue to remain highly interested and continue to be very active in that regard.
Awesome. Thank you, guys.
Yeah.
We'll go next to Shneur Gershuni with UBS.
Hi, good morning, guys.
Good morning.
Just maybe to stick on the whole ethane thesis for a bit. There's sort of a broader thesis out there about the Permian tightness for capacity to evacuate natural gas out of the basin could incentivize more recovery of ethane in the Permian at the expense of other basins. Is that incorporated into your ethane recovery view? You've kind of had a bigger number this quarter, but you're still guiding to a lower number. I'm just trying to square the circle here.
Sheridan, this is Kevin. As we look at ethane recovery, our premises haven't changed. We still are confident in the numbers we see coming out. You're seeing some downward pressure on gas basis in the Permian. By and large, we believe the vast majority of ethane is already being recovered out of the Permian. How much incremental ethane can continue to come out? I don't think that changes our point of view, that we're still going to see ethane come out in the Mid-Continent, given the demand we've seen come online, and the demand we expect to come online the remainder of the year. I mean, Sheridan, you know anything.
The only thing I'd add is we're also seeing some pressure on Mid-Continent gas prices as well, which is making ethane to be extracted Mid-Continent competitive with the Permian.
Fair enough. Sort of continuing on the Permian gas theme. Roadrunner, is that an option that you guys can flip or do something with as kind of a response to what's going on in the Permian?
We're in active discussions with several companies out there to utilize our West Texas system and also the Roadrunner system to potentially move gas bidirectionally. Connections to potentially move gas to the west, to the El Paso and Mexico markets, or back to the east, back to the WAHA market on Roadrunner. Similarly, with the West-Tex intrastate system, a lot of conversations of potentially some services around the WAHA hub, and also looking at bidirectional capabilities to take gas out of WAHA back to the north up to other interstate markets in the Texas Panhandle and Western Oklahoma. A lot of activity going on with our commercial team on the gas pipeline side. Obviously as we get some of those inked up, we may make some announcements.
Let's say you FID a decision, given the various options you're looking at. How long would that actually take to execute?
I'm sorry, I didn't catch the first part.
How long would it take?
Oh, how long it would take. No, these projects are very low capital, very quick time frames. We're talking weeks or months, not years. This is install some compression, maybe have to install a little piping, and we're done.
Great. Thank you very much, guys. Appreciate the color.
Thank you.
We'll go next to Christine Cho with Barclays.
Hi, everyone.
Hey, Christine.
The last time the Mont Belvieu-Conway spread was wide, you guys had a decent amount of capacity for your proprietary use. Last quarter, you said Sterling was about 60%-70% utilized. I think that leaves 130,000, 140,000 barrels per day open. I'm guessing some of that is expected for the ethane extraction that you're expecting, and some of that's for just general growth in Oklahoma production. If ethane rejection doesn't fall from 140,000 to 70,000 barrels per day by year-end, does that mean you essentially have 70,000 barrels per day that you could use for optimization? Just trying to figure out how we should think about the impact of wider spreads for you.
Christine, this is Sheridan. I think you're looking at it right. To the extent that ethane does not come out, that does leave us more opportunity for optimization. We are seeing volume growth today that's probably pushing our Sterling system to the 80%-90% range. Also one thing we are seeing today is also we're moving more Y-grade onto the bigger line, the Sterling III line, that we can't utilize all the capacity, so we get a little bit of degradation there. There's no doubt if the ethane doesn't come out, these spreads are staying wide, optimization will more than cover that shortfall.
Okay. One of your competitors, who's currently building a pipeline in Texas, announced that it's also going to be building a line to connect to their plants in the Mid-Con. Should we think that there is a potential for volumes to come off your line in the future, or is this more of an opportunity cost and that volumes from their future plants will likely be going down that line?
That pipeline will connect into a plant that's currently on our system. We will probably see about 20,000 barrels a day come off our system later this year. I think that will be the extent of it. As Kevin mentioned in his statements earlier, we've already contracted more volumes in the Mid-Continent, and part of that is in the Arkoma. We do not see that will prevent us from continuing to secure plant commitments in that area.
Okay, great. Do you expect the change in flaring rules in the Bakken to impact you guys at all on the G&P front?
Christine, it's Kevin. No, we don't. Historically, our flaring has been at or below the state flaring capture targets, and we've been below the statewide averages. We get to the wells in a timely manner. With the capacity we have available right now and the expansions and the new plant we're talking about, we still feel good that we'll be able to stay ahead of those targets. We don't necessarily think the new regulations will have any impact on us. Chuck, anything you-
I think the only thing I would add to that is with flaring rules going from 14 to 60 days for the producer, as Kevin said, we've connected these pads and these wells very quickly. That extra 46 days It's not even an impact to us because we're typically out there tied in already.
Lastly, I vaguely remember you guys awarding one share to all of your employees every time the stock hits an all-time high. You guys aren't that far off from your high. The next time this happens, what's the impact on G&A?
Actually, I don't think we've actually provided that estimate in the past, so I'm not going to provide it now. I'm hoping that's a problem.
Okay. Thank you, guys.
You bet. Thank you.
We'll go next to Praneeth Satish with Wells Fargo.
Hi. Good morning. I'm sure you're aware that ethylene margins have declined. Just curious on your thoughts on this and whether you see this as just a temporary risk or a longer-term issue.
Praneeth, I think broadly it's a temporary issue, and Sheridan can give you some more color.
Yeah. This is Sheridan. I think the big thing you need to look at is, and you've heard other companies say the same thing, is if you look at the ethane to polyethylene spread, they're significantly wider now than they were a year ago. That's really what these crackers are looking at, what the fundamentals are. We're still seeing great demand for polyethylene out there. I think you're really talking about a temporary phenomenon at this time.
You have some excess ethylene inventory.
Yeah. We came into the month. We heard it came in, the crackers came in, little excess inventory. They just need to get their derivative units ramped up to get this cleaned up. I think you're saying it's going to be cleaned up the next couple of months to quarters.
Got it. Can you just talk about where you stand on gas takeaway in the Bakken with respect to BTU limits, I guess, on Northern Border. Tied to that question, if we are hitting limits, could we start to see meaningful ethane recovery out of the Bakken on Elk Creek?
Yeah, this is Kevin. We still feel good about where we're at right now with the residue going into Northern Border. We're not seeing any downstream impacts. As we've talked about that, yes, if you continue to push higher BTU content into Northern Border, and it's displacing drier Canadian or lower BTU Canadian gas, then you could get to the point where you would see some downstream impacts. We don't see that happening in the next couple of years. That's going to be driven more from the volume growth in the Bakken and what happens there. It's not an immediate problem and/or opportunity for us, but it is something that we're clearly keeping our eye on.
Okay. Thank you.
We'll go next to Jeremy Tonet with J.P. Morgan.
Yeah, hi. This is Charlie in for Jeremy. On the G&P segment, it appears your average fee rates were pretty high this quarter. I understand it's largely a mix shift impact, but curious if you could expand here and if $0.80 is still the right way to look at it.
Yeah, Jeremy, this is Chuck. Going into the quarter, obviously, we expected the $0.80 average fee rate to in fact be there. As we went through the quarter and ultimately exited the quarter, our Midcontinent volumes were up, so you would expect that fee rate would have declined or been in the $0.80 range. However, our Bakken fee rate increased due to volume from certain large 100% fee-based contracts. If you recall, we have really several kinds of contracts, some 100%, some 100% with a little bit of pop. These were large 100% fee-based contracts that ultimately caused the segment's overall fee rate to increase to that $0.88 level.
Yeah, the only thing I'd add.
Okay.
Go ahead.
No, you go.
I was just going to say, a lot of that is driven by weather. When you think about what's going on in both the Williston and Oklahoma, you have certain areas where you have more wells offline and that impact different contracts. It's not uncommon for us to see a little bit of noise related to that fee rate due to the weather impacts.
Okay. That's helpful. Thanks. On your optimization and marketing results, just kind of curious what NGL products you're optimizing during the quarter.
Right now we're seeing E/P spreads in the $0.16 range, propane in the $0.15, and normal butane in the $0.18. We're pumping as much as all that we can.
All right. Last one from me. G&P segment, apologies if I missed it, but can you discuss the higher third-party processing costs and system constraints?
Yeah. This is Kevin. That was really kind of an isolated phenomenon in the first quarter. As we've talked about the 200 million a day long-term third-party offload we have, as we were transitioning volumes from kind of other third-party offloads that we were kind of using to bridge into that, as we worked through the startup process on the long-term offload, we incurred some additional cost as we worked through that transition. That's really what that was. Similarly, just some other constraints that were going on as we saw the volume growth and as we were trying to move volumes around to ensure that we got it to a processing plant. We had some of that. We do not expect those costs to continue as we have transitioned to our longer-term third-party offload that's fully in service and is at much more attractive rates.
Okay. Shouldn't see anything show up in 2Q then?
No.
Great. Thank you very much.
We'll go next to Brian Zarahn with Mizuho.
Good morning.
Good morning.
We discussed Permian gas takeaway projects that you're evaluating. Any update on potential expansion of your NGL system in the Permian?
Yeah, this is Sheridan. We continue, and we're in some advanced discussions with a couple other producers and processors in there. So we're expecting to hear, hopefully in the short term, we'll have something more to talk about on the West Texas system. As we've done in the past, we usually don't announce expansions until we've secured the contracts behind them.
Appreciate the update. In the Permian, I guess, on your projects overall, any impact on higher steel costs?
As we've talked before, we had procured and locked in the steel prices for the pipe several months ago, actually. We're in great shape from a steel perspective.
On financing, if you could elaborate a bit on your expectation of no equity, potentially not at all in 2019. Is the key driver more if you have additions to your project backlog, or is it more the cash flow ramp and marketing contributions?
I think that is if we were in a position where we saw an attractive project that we needed to add, then we'd have to think a little bit harder about whether some equity was appropriate. The reason we put the qualifier at all, as we see the business moving today, and the fact that we're starting today at a 3.5 debt-to-EBITDA ratio, we've got some pretty good room there for debt capacity going forward as EBITDA expands.
Thank you.
Thank you.
We'll go to Theodore Durbin with Goldman Sachs.
Thanks. Just the 140,000 barrels a day of ethane rejection across the system, can you give us the split between the Williston and the Midcontinent?
Yeah, it's about 50 to 70,000 barrels a day in the Williston and about 70 to 100,000 barrels a day in the Midcontinent.
Okay. Got it. I realize that changes based on the processing economics. If we think about the Elk Creek, the early Elk Creek expansion you're doing, how much volume can you get out of that Bakken NGL Pipeline with that early construction you're doing?
I think we could get another 10,000-15,000 barrels a day down the pipeline, but also that will relieve some more of the rail volume that had to go on rail. It's probably another 15,000-20,000 barrels a day that we could increase coming out of the Bakken to go out of our rail terminal.
Got it.
This will give us about a 25,000 barrel a day. It could give us a 25,000 barrel a day uplift.
Okay, that would be at the same sort of $0.30 economics that you've talked about before?
Probably a little bit. We've said that when we contracted Elk Creek, it was a little bit less than that $0.30 that we've seen before, it's going to be in the high 20s.
Got it. Okay, that's helpful. Just this additional contracting that you've done both on the Elk Creek and Arbuckle with the additional commitments, is that pushing us closer to the midpoint of the 4 to 6 times build multiple range? Is that kind of close to the low end? How do we think about the returns now with the new commitments?
How I think it returns with these new commitments is we will get to the 4 to 6 faster because we'll have more of the ramp-up coming in quicker, we will push more towards the lower end, if not even lower than the 4 times.
Got it. That's great. Last one for me, just kind of some cleanups. Can you quantify the impact of weather this quarter on your volumes and your revenues, and I guess by segment, if you have it? The impact of the NGL inventory sale, how much did that impact the results?
From a weather standpoint, we haven't necessarily quantified that. We've kind of given you where we're at in April. From a G&P perspective, process volumes, it was normal. Again, it's not uncommon for our volumes to be slightly off relative to Q4. The fact that we were up was a very positive signal from a weather standpoint. I don't think we're going to go down the path of splitting out kind of our optimization or the details of the optimization in marketing from an NGL held in inventory.
Okay, thanks. That's it for me.
Thank you.
We'll go next to Craig Shere with Tuohy Brothers.
Good morning. Congratulations on continued great execution here.
Thanks, Craig.
Asked and answered. Just picking up on Ted's question about the NGL inventory with marketing to the degree that you aren't quantifying it. Do you then need to rebuild? Is that a headwind in future periods? How should we think about that?
No, I don't view it as a headwind at all. Again, Sheridan talked about the spreads we're seeing right now, in a previous question also talked about the capacity we have for optimization, and that if ethane shows up, great, but even if it doesn't with these spreads, there's the opportunity. We'll see an offset there. That's how I'd think about it going forward, is we do believe the spreads will remain strong, you would expect to see that optimization bucket stay strong.
Okay. You addressed the higher G&P OPEX for the quarter, that a lot of that was temporary. I think there was some lower expense in the NGL segment. How should we think about that?
You kind of had a little bit of both in those. I think what we're trying to get at is kind of run rate. In the G&P segment, a run rate might be a little lower than what we saw in the first quarter because of some of these costs. You've also got volume growth, as you go through the year, you'll see a little step up in op cost just to deal with that volume growth. On the NGL side, we saw a higher op cost in the fourth quarter. We had several maintenance projects and expense projects and work that we did in the fourth quarter that it was probably a little artificially high. You saw a step down. Kind of a run rate there might be probably closer towards Q1, maybe a little above that.
Again, as you see volume growth through the rest of the year, you're going to see a little uptick there as well.
Great. Thank you for the clarifications.
We'll go next to Becca Followill with U.S. Capital Advisors.
Good morning. Just following up on the fee rate of $0.88 versus the guidance of $0.80. Are you saying that $0.80 is probably the good go-to number for the rest of the year?
Becca, it's Kevin. Yeah, that's what I would use at this point. That will depend on how the volumes come on which contracts. We do believe we saw some anomalies in the first quarter that drove it up a little bit, and you'll see it come back down as kind of the weather gets out and our customers get back to some of their drilling programs and you see the volume growth. We do think that will tick down a little bit.
Thank you. Back to the Texas intrastate market and what you can do there. Can you quantify how much additional capacity you can add to evacuate gas north?
We're not talking Bcf a day type projects. You probably got two or three different projects in the 100 to 300 million a day type range. These are a little more tactical projects that we're talking about. Again, low capital, low multiple, building off our existing asset footprint. That's how I would think about those types of projects.
Super. Thank you guys.
Go next to Ethan Bellamy with Baird.
Good morning, guys. Just to follow up on Brian's question on steel prices. A couple questions in that area. First, can you confirm you're not exposed on Elk Creek? Separately, other projects in your backlog, either announced or unannounced, has that meaningfully moved or changed the economics there or the viability? Finally, will we see any movement in maintenance CapEx costs going forward if steel prices maintain current levels?
Well, I'll take the first one. Elk Creek, no, we're not exposed there. Again, we bought that pipe. It's already showing up, and we're locked in from a price perspective. Nothing there. As we think about our backlog and other things, we have not seen any other kind of ancillary cost escalation at this point, and feel good about those projects that we've already announced. As we think about our backlog, obviously, the tariff stuff continues to evolve, as we move through it, we'll include anything there in our economics as we evaluate the economics.
Kevin, you might mention Arbuckle in terms of where we are in steel there.
That's right. We focused on Elk Creek, but Arbuckle II is also locked in as well from a steel price standpoint. Got the vendors locked in, prices locked in, schedules locked in, and we're good to go there.
In terms of anything you might be negotiating with customers, does it delay potential negotiated agreements on new lines if you don't know what the cost of the project's going to be?
No.
Okay. Just kind of a housekeeping item, we've seen a few small North Dakota flood warnings. Anything to be concerned about for Q2?
No. What's that?
Not outside the ordinary.
No. Again, normal to me as we move through April and May, we've seen what we would consider a normal spring.
Okay. Thanks a bunch.
That concludes today's question and answer session. At this time, I'll turn it back to Mr. Ziola for any additional closing remarks.
Our quiet period for the second quarter of 2018 starts when we close our books in early July and will extend until we release earnings in late July. We'll provide details on the conference call at a later date. Thank you all again for joining us, and have a good day.