Oneok Inc (OKE) — Q1 2018 Earnings Call Transcript

Thank you, Mindy, and good morning. And welcome to ONEOK’s first quarter 2018 earnings conference call. This call is being webcast live and 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 and thank you all for joining us today. As always, we appreciate your continued interest and investment in ONEOK. Joining me on today’s call is Walt Hulse, Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs; 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. But 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, and we’re making good progress so far. On the natural gas liquids side, we continue to work with landowners, state and local agencies, and other stakeholders along the pipeline routes for Elk Creek and Arbuckle II, and 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 action would allow barrels from the Powder River Basin to flow on Elk Creek before the entire line is complete, which could 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 MB-4 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 remained key drivers of our 2018 guidance. And 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’ll 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 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 the 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 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. But we continue to view leverage of 4 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 quarter with no outstanding commercial paper and nearly the full $2.5 billion available on our credit facility. Since December 31, 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 announcements and 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 taxable 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 of 2020. Midwestern, which 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. And 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 will 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 Mid-Continent, a trend that we expect to continue throughout 2018. Winter weather impacted first quarter volumes relative to the fourth quarter, but we’ve since seen 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 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; however, 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 are 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 our 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 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. Additionally, our 200 million cubic feet per day Demicks Lake plant is expected to be completed in the fourth quarter 2019. In the natural gas pipelines 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 and 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. But 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 our 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 on our facilities, the fires did affect and caused 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 square miles. I want them to know that we’re thinking about them as they recover and rebuild. Much work lies ahead for those impacted by the fires. And 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. And as always, thank you to our employees for your hard work and continued dedication to operating our assets safely and environmentally responsibly. So, with that, operator, we’re now ready for questions.

Good morning, guys. You’ve talked in the past about Mid-Con processing each 200, and that plant produces roughly 20,000 to 25,000 barrels a day of NGLs. Can you just remind me what’s a decent rule of thumb for the Bakken, 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.

Okay, I’ve been reflecting on this. A year ago, the Bakken pipeline was practically at capacity. Looking at the statewide data from February to February, there’s nearly a 400 Mcf per day increase year-over-year. Essentially, this math would imply an additional 50,000 barrels per day. I'm trying to contextualize this: to reach 100,000 barrels per day at Elk Creek, are you suggesting that, based on what is being transported out of the basin now, you are approximately halfway to your target returns?

First, we’re not using rail today. Therefore, the pipeline has been able to operate slightly above its capacity. Last year's numbers included some additional ethane in the barrels due to downstream specification issues. We have since managed to remove some of that ethane and substitute it with C3 Plus as more ethane has become available from other areas flowing into the Mid-Continent frac assets. As we continue rail operations and assess our available capacity, including the addition of the Demicks Lake plant and the Bear Creek expansion, it is clear that we are making significant progress towards fulfilling commitments and achieving the projected numbers for Elk Creek.

I guess, maybe switching a bit. I just want to ask, I know you have the question fairly regular but around ethane and NGL exports more broadly. If you look at your asset portfolio, you are probably the largest player without an export terminal in-house. And recognizing that your molecules can still get to the docks today, still potential margin opportunity. How aggressively would you be pursuing other export terminals? We saw another player announced a JV, someone came in on an ethane terminal? Is that something you are after or could be there, what would be a structure for that that might be interesting?

Yes, Eric, this is Terry. We have been considering exports for many years and have actively sought opportunities in this area. A few years ago, we were close to a venture with a third-party joint venture partner, but it didn’t go through due to significant erosion of the economics. We are still focused on the export side. If we were to launch an export project, it would likely involve a potential joint venture. This could either use existing facilities that require modifications or consist of a completely new facility. We remain very interested in developing export capabilities. While it's not essential for us since we already have international relationships and market access, it would enhance our service offerings as it represents a solid fee-based business. So, yes, we continue to be very active and highly interested in pursuing this.

Just maybe to stick on the whole ethane thesis for a bit. There is 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 recoveries? You had a bigger number this quarter, but you still got into a lower number. I’m just trying to square the circle here.

As we consider ethane recovery, our stance remains unchanged. We are confident in the numbers we are seeing, although there is some downward pressure on gas basis in the Permian. However, we believe that the majority of ethane is already being recovered from the Permian. The question is how much additional ethane can be extracted. I think this does not alter our view that we will continue to see ethane coming from the Mid-Continent, especially considering the demand that has emerged and the expectation for demand to increase throughout the year.

One thing I’ll add is we’re also seeing some pressure on Mid-Con and gas prices as well, which is making ethane to be extracted and Mid-Con very competitive with Permian.

Okay, fair enough. And then, 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?

Yes. We’re in active discussions with several companies out there to utilize our WesTex system and also the Roadrunner system to potentially move gas bidirectionally. So, 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 WesTex 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. So, a lot of activity going on with our commercial team on the gas pipeline side. And 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. These projects are very low capital, very quick timeframes. We’re talking weeks or months, not years. This is install some compression, maybe you have to install little piping and we’re done.

Last time the 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% to 70% utilized. So I think that leaves 130,000 to 140,000 barrels a 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 spread for you.

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’re seeing volume growth today that’s probably pushing our Sterling system to the 80 to 90% range. And then, also, one thing we are seeing today is also we’re moving more wide grade onto the bigger line the Sterling III line if we can’t utilize all the capacity. So, we get a little bit of a degradation there. So, there is no doubt. If the ethane doesn’t come out, these spreads are staying wide, optimization will more than cover that shortfall.

Okay. And then, one of your competitors who is 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 volume from their future plants will likely be going down that line?

Yes. That pipeline will connect to a plant that’s currently on our system. We will likely see about 20,000 barrels a day come off our system later this year, but I think that will be the extent of it. As Kevin mentioned earlier, we’ve already contracted more volumes in the Mid-Continent, including part of that in the Arkoma. Therefore, we believe this will not hinder our ability to secure plant commitments in that area.

And then, 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 consistently been at or below the state flaring capture targets, and we have been below the statewide averages. We are able to access the wells promptly with our current capacity, along with the expansions and the new plant we are discussing. We remain confident that we will continue to meet those targets. We don’t believe the new regulations will have any effect on us. Chuck?

I think, the only thing I’d add to that is with flaring rules going from 14 to 60 days for the producer, as Kevin said, we connected these pads and these wells very quickly that extra 46 days, it’s not even an impact to us because we typically get out there and tie it already.

And then, lastly, I basically 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 high. The next time this happens, what’s the impact on G&A?

I don’t think we’ve actually provided that estimate in the past. So, I’m not going to provide it now. But I’m hoping that’s a problem.

I’m sure you are 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.

The key point to consider is that the ethane to polyethylene spreads are much wider now compared to a year ago. This is what the correctors are focusing on regarding the fundamentals. We are still observing strong demand for polyethylene. Therefore, I believe this is a temporary situation at this moment.

And you have some excess ethylene inventory?

We came in and at the last we heard we came in; the crackers came in with little excess inventory, they just need to get to derivative units ramped up to hit this point out. So, I think you are seeing it’s going to be cleaned up in the next couple of months, the next couple of months to quarters.

And then, can you just talk about where you stand on gas takeaway in the Bakken with respect to BTU limits, so I guess the Northern Border? And then, tied to that question, if we are hitting limits, could we start to see meaningful ethane recovery out of the Bakken on Elk Creek?

This is Kevin. We still feel good about where we’re at right now with the residue going into Northern Border. We are not seeing any downstream impacts. Now, as we have talked about that, yes, if you continue to push higher BTU content into Northern Border and it’s displacing dryer Canadian or lower BTU Canadian gas, then you could get to the point where you would see some downstream impacts. But, we don’t see that happening in the next couple of years. But, that’s going to be driven more from the volume growth in the Bakken and what happens there. So, it’s not an immediate problem and/or opportunity for us, but it is something that we’re clearly keeping our eye on.

This is Sterling for Jeremy. On the G&P segment, it appears your average fees were pretty high this quarter. I understand it’s a larger than mix shift impact. But curious if you can expand, $0.80 is still the right way to look at it.

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, yes, our Mid-Continent volumes were up. So, you would expect that fee rate would have declined or be 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. But, these were large 100% fee-based contracts that ultimately caused the segment’s overall fee rate to increase to the $0.88 level.

The only thing I’d add...

...I was just going to say, a lot of that is driven by the 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 did impact different contracts. So, 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. And on your optimization and marketing results, just kind of curious what NGL products you’re optimizing during the quarter.

Right now, we’re seeing EP spreads in the $0.16 range; propane in the $0.15 and normal butane in the $0.18. So, we’re pumping as much of all that as we can.

And then, last one for me. G&P segment, I apologize if I missed it. But can you discuss the higher third-party processing costs and system constraints?

This is Kevin. That was really kind of an isolated phenomenon in the first quarter. As we talked about the 200 million a day third-party long-term third-party offload we have, as we were transitioning volumes from other third-party offload that we were kind of using as a bridge into that, as we worked through the startup process on the long-term offload, we incurred some additional costs as we worked through that transition. That’s really what that was. And similarly, just from 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. But we do not expect those costs to continue as we have transitioned to our longer-term third-party offload. It’s fully in service and is at much more attractive rates.

So, shouldn’t see anything show up in 2Q then?

No.

You discussed Permian gas takeaway projects that you’re evaluating. Any update on potential expansion of your NGL system in the Permian?

This is Sheridan. We are currently in advanced discussions with a few other producers and processors. We hope to have more updates regarding the West Texas system in the near future. However, as we have done previously, we typically wait to announce expansions until we have secured the necessary contracts.

In the Permian, I guess, on your projects overall, any impact on higher steel costs?

No. As we have talked before, we had procured and locked in the steel prices for the pipe several months ago actually. So, we are in great shape from a steel perspective.

And then, on financing, if you could elaborate a bit on your expectation, no equity potential in 2019. Is a key driver more, so you have additions to your project backlog or is it more the cash flow ramp and marketing contributions?

I think that if we were in a position where we saw an attractive project that we needed to add but then we would have to think a little bit harder about whether some equity was appropriate. But, the reason we put the qualifier at all, as we see the business moving today and the fact that we are starting today 3 and hey, if you annualize the first quarter at 3.5 debt to EBITDA ratio, we’ve got some pretty good room there for debt capacity going forward as EBITDA expands.

Just the 140,000 barrels a day of ethane rejection across the system, can you give us the split between the Williston and the Mid-Continent?

Yes, it’s about 50,000 to 70,000 barrels a day in the Williston and about 70,000 to 100,000 barrels a day in Mid-Continent.

Okay, got it. I realized that changes based on the process and economic. So, 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 pipeline with that early construction you are doing?

I think we can get another 10,000 to 15,000 barrels a day down the pipeline, but also that will release more of the rail volume; it had to go on rail, probably another 15,000 to 20,000 barrels a day that we could increase coming out of Bakken to go out of our rail terminal. So, I think overall that will give us about 25,000 barrels a day, could give us 25,000 barrels a day.

And that would be at the same sort of $0.30 economics that you talked about before?

Probably a little bit. We said that when we contracted Elk Creek it was a little bit less than that $0.30 that we have seen before but it’s going to be in the high 20s.

And then, 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, close to low-end, how do we think about the returns now with the new commitments?

I believe the new commitments will help us reach the 4 to 6 times range more quickly because we will see a faster ramp-up. We will likely aim for the lower end, potentially even below four times.

Can you quantify the impact of weather this quarter on your volumes and revenues, and I guess by segment if you have it? And then, the impact of the NGL inventory fell, how much did that impact the result?

From a weather standpoint, we haven't quantified that specifically; we've shared our status as of April. From a gathering and processing perspective, our process volumes were normal, and it's not unusual for our volumes to be somewhat lower compared to Q4. Therefore, the increase we experienced was a positive indication regarding the weather. Additionally, we will not be discussing the details of our optimization and marketing strategies related to the NGLs held in inventory.

Good morning and congratulations on the continued great execution here. Most of my questions have been asked and answered. I wanted to follow up on Ted’s question regarding the NGL inventory with marketing. If you aren't quantifying it, do you need to rebuild it? Will that be a challenge in future periods, and how should we consider this?

I don’t view it as a headwind at all. Again, Sheridan talked about the spreads we’re seeing right now. And a previous question also talked about the capacity we have for optimization. And if ethane shows up, great, but even if it doesn’t, with the spreads there’s the opportunity we will see an offset there. So that’s how I think about it going forward is we do believe the spreads will remain strong. And so you would expect to see that optimization bucket stay strong.

And you addressed the higher G&P OpEx for the quarter that a lot of that is temporary. I think there was some lower expense in the NGL segment. How should we think about that?

You experienced a mix of factors in those areas. If we consider our run rate, it might be slightly lower in the G&P segment compared to the first quarter due to some costs. However, there is also volume growth to factor in. Throughout the year, you can expect a slight increase in operating costs to accommodate that volume growth. On the NGL side, operating costs were elevated in the fourth quarter due to several maintenance and expense projects that we undertook, which may have appeared artificially high. Following that, we noticed a decrease. Therefore, the run rate there is likely to align more closely with Q1, possibly even a bit higher. As volume growth continues over the year, a slight uptick in costs will also be observed.

Good morning. Just following up on the fee rate at $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?

Yes, that’s what I would suggest at this time. It will depend on how the volumes come in and which contracts are involved. We believe we observed some irregularities in the first quarter that caused an increase, and you can expect it to decrease as the weather improves, our customers resume their drilling programs, and we see volume growth. We anticipate this will taper off a bit.

And then 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 are not discussing projects that operate in terms of Bcf a day. Instead, we are looking at two or three different initiatives in the range of 100 million to 300 million a day. These are more tactical projects that we are considering. They involve low capital and low multiples, building on our existing asset base, and that’s how I’d like you to think about these types of projects.

Just a follow-up on Brian’s question on the steel prices, a couple questions in that area. First, can you confirm you are not exposed on Elk Creek? Separately, other projects in your backlog, either announced or unannounced, has that meaningful moved or changed the economics there, the viability? And then, finally, will we see any movement in maintenance CapEx cost going forward if steel prices maintain current levels?

I’ll address the first question. No, we are not exposed at Elk Creek. We purchased the pipe, and it is already reflecting in our figures. We are secured on pricing, so there are no issues there. In terms of our backlog and related matters, we haven’t observed any additional cost increases at this time and are confident in the projects we’ve already disclosed. Regarding our backlog, the situation with tariffs is still developing. As we progress, we will incorporate any relevant factors into our economic analysis.

Kevin, you might mention Arbuckle in terms of the steel...

Yes. That’s right. We’re focused on Elk Creek but Arbuckle II is also locked in as well from the steel price standpoint. So, we have got the vendors locked in, prices locked in, schedules locked in, and we are good to go there.

And in terms of anything you might be negotiating with customers, does it delay potential negotiated agreements on new plants if you don’t know what the cost of the project is going to be?

No.

Just the 140,000 barrels a day of ethane rejection across the system, can you give us the split between the Williston and the Mid-Continent?

Yes, it’s about 50,000 to 70,000 barrels a day in the Williston and about 70,000 to 100,000 barrels a day in Mid-Continent.

Okay, got it. I realized that changes based on the process and economic. So, 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 pipeline with that early construction you are doing?

I think we can get another 10,000 to 15,000 barrels a day down the pipeline, but also that will release more of the rail volume; it had to go on rail, probably another 15,000 to 20,000 barrels a day that we could increase coming out of Bakken to go out of our rail terminal. So, I think overall that will give us about 25,000 barrels a day, could give us 25,000 barrels a day.

And that would be at the same sort of $0.30 economics that you talked about before?

Probably a little bit. We said that when we contracted Elk Creek it was a little bit less than that $0.30 that we have seen before but it’s going to be in the high 20s.

And then, 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, close to low-end, how do we think about the returns now with the new commitments?

I believe that with these new commitments, we will reach the 4 to 6 range more quickly because the ramp-up will come sooner. We will aim for the lower end, possibly even below the 4 times.

Can you quantify the impact of weather this quarter on your volumes and revenues, and I guess by segment if you have it? And then, the impact of the NGL inventory fell, how much did that impact the result?

From a weather standpoint, no, we’re not. We haven’t necessarily quantified that from where we’re at in April. From a G&P perspective, process volumes were normal again. It’s not uncommon for our volumes to be slightly off relative to Q4, so the fact that we were up was a very positive signal from a weather standpoint. I don’t think we’ll be splitting out our optimization or the details of the optimization and marketing from the NGLs held in inventory.

Good morning and congratulations on your continued great execution. Most of my questions have been asked and answered. Following up on Ted’s question about the NGL inventory with marketing, if you're not quantifying it, do you need to rebuild it? Will that be a challenge in the future periods, and how should we view that?

I don’t view it as a headwind at all. Again, Sheridan talked about the spreads we’re seeing right now. And a previous question also talked about the capacity we have for optimization. And if ethane shows up, great, but even if it doesn’t, with the spreads there’s the opportunity we will see an offset there. So that’s how I think about it going forward is we do believe the spreads will remain strong. And so you would expect to see that optimization bucket stay strong.

And you addressed the higher G&P OpEx for the quarter that a lot of that is temporary. I think there was some lower expense in the NGL segment. How should we think about that?

You had a mix of factors at play. We're aiming for a specific run rate. In the G&P segment, the run rate may be slightly lower than what we experienced in the first quarter due to certain costs. However, there is also volume growth to consider. As the year progresses, you might notice an increase in operating costs to accommodate that volume growth. On the NGL side, operating costs were elevated in the fourth quarter due to various maintenance and expense projects we undertook, which were likely higher than usual. Subsequently, there was a decrease. Therefore, the run rate there may align more closely with Q1, possibly slightly above it. Again, with continued volume growth throughout the year, you can expect a modest increase in those costs as well.

Good morning. Just following up on the fee rate at $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?

Yes, that's what I would rely on at this point. It will depend on how the volumes come in and which contracts are involved. We did notice some anomalies in the first quarter that caused a slight increase, but we expect it to decrease as the weather improves and our customers resume their drilling programs, leading to volume growth. We believe there will be a slight decline in that regard.

And then 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 are not discussing projects in the range of Bcf a day. Instead, we are looking at two or three different projects that fall within the range of 100 million to 300 million a day. These are more tactical projects, characterized by low capital investment and low multiples, and they leverage our existing asset footprint. That's the perspective I have on these types of projects.

Our quiet period for the second quarter of 2018 starts when we close our books in early July and we will extend until we release earnings in late July. We will provide details on the conference call at a later date. Thank you all again for joining us and have a good day.