Current OKE Stock Info

ONEOK, Inc. (Ticker: OKE) announced higher third-quarter 2017 financial results primarily benefiting from natural gas and natural gas liquids (NGL) volume growth in the Williston Basin and STACK and SCOOP areas, higher average fee rates in the natural gas gathering and processing segment and higher fee-based transportation services in the natural gas pipelines segment.

Highlights

  • Maintaining 2017 net income guidance of $635 million to $795 million, adjusted EBITDA guidance of $1.89 billion to $2.06 billion and DCF guidance of $1.28 billion to $1.44 billion
  • Announcing in October 2017 plans to invest approximately $200 million to extend the West Texas LPG Pipeline system, of which ONEOK owns 80 percent, into the prolific Delaware Basin. The project is expected to be completed in the third quarter 2018
  • Repaying in September 2017 $400 million of 2.0 percent senior notes
  • Completing in July 2017 a $1.2 billion public offering of senior notes, consisting of $500 million of 10-year senior notes at a coupon of 4.0 percent and $700 million of 30-year senior notes at a coupon of 4.95 percent, generating net proceeds of approximately $1.18 billion
  • Repaying in July 2017 $500 million of the $1.0 billion term loan agreement due 2019
  • Redeeming in July 2017 ONEOK’s 6.5 percent senior notes due 2028 for approximately $87 million
  • Having approximately $1.6 billion of borrowing capacity available under its $2.5 billion credit agreement as of Sept. 30, 2017
  • Declaring in October 2017 a third-quarter 2017 dividend of 74.5 cents per share, or $2.98 per share on an annualized basis. The dividend remains unchanged from the previous quarter when it was increased 13 cents per share, or 21 percent, following the close of the ONEOK and ONEOK Partners merger transaction.

Natural Gas Liquids (NGLs)

The natural gas liquids segment’s adjusted EBITDA increased 5 percent in the third quarter 2017, compared with the same period in 2016, benefiting from increased NGL volumes gathered from the Williston Basin and STACK and SCOOP areas.

The segment connected one new third-party natural gas processing plant in the Permian Basin during the third quarter 2017, in addition to the five third-party plant connections added to its system in the first half of 2017.

Even with higher NGL volumes gathered during the third quarter 2017, compared with the second quarter 2017, ethane rejection levels on ONEOK’s system remained relatively unchanged, continuing to average more than 150,000 barrels per day (bpd).

During August and September 2017, disruptions from Hurricane Harvey caused lower NGL volumes and higher operating costs at some of ONEOK’s Gulf Coast and Mid-Continent area assets, adversely impacting adjusted EBITDA in the segment by an estimated $4.5 million.

The increase in third-quarter 2017 adjusted EBITDA, compared with the third quarter 2016, primarily reflects:

  • A $17.4 million increase in exchange services due to increased volumes in the Williston Basin and the STACK and SCOOP areas from recently connected natural gas processing plants, offset partially by lower volumes in the Granite Wash and Barnett Shale and reduced volumes related to Hurricane Harvey
  • A $7.5 million increase in optimization and marketing due primarily to wider product price differentials
  • A $10.4 million increase in operating costs due primarily to higher property taxes, higher labor and employee-related costs associated with benefit plans, the timing of routine maintenance projects and additional operating costs related to Hurricane Harvey
  • A $4.2 million decrease in transportation and storage services due primarily to lower storage volumes.

 

Natural Gas Gathering and Processing

The natural gas gathering and processing segment’s adjusted EBITDA increased 29 percent in the third quarter 2017 and 17 percent through the first nine months of 2017, compared with the same periods in 2016. Producer activity remained steady on ONEOK’s dedicated acreage in the Williston Basin and STACK and SCOOP areas, contributing to a 16 percent increase in natural gas volumes processed, compared with the third quarter 2016.

Higher fee-based earnings also continue to benefit the segment, with the third quarter 2017 fee rate averaging 86 cents per MMBtu, compared with 76 cents per MMBtu in the third quarter 2016, a 13 percent increase.

During the third quarter 2017, the gathering and processing segment recorded $20.2 million of noncash impairment charges related to nonstrategic assets and equity investments located in North Dakota and Oklahoma, respectively.

Third-quarter 2017 adjusted EBITDA increased, compared with the third quarter 2016, which primarily reflects:

  • A $26.5 million increase due primarily to natural gas volume growth in the Williston Basin and the STACK and SCOOP areas, offset partially by natural production declines
  • A $16.9 million increase due primarily to restructured contracts resulting in higher average fee rates, offset partially by a lower percentage of proceeds (POP) retained from the sale of commodities purchased under POP with fee contracts
  • A $10.8 million increase in operating costs due primarily to increased labor and employee-related costs associated with benefit plans and the growth of ONEOK’s operations and the timing of property tax accruals
  • A $3.1 million decrease due primarily to lower realized natural gas and condensate prices.

 

Natural Gas Pipelines

The natural gas pipelines segment’s adjusted EBITDA increased 9 percent in the third quarter 2017 and 13 percent through the first nine months of 2017, compared with the same periods in 2016. Higher fee-based earnings and increased transportation capacity contracted, primarily from the 2016 WesTex pipeline expansion, contributed to the segment’s results.

Third-quarter 2017 adjusted EBITDA increased, compared with the third quarter 2016, which primarily reflects:

  • A $6.7 million increase from higher transportation services due primarily to increased firm demand charge capacity contracted
  • A $2.7 million increase in equity in net earnings from investments due primarily to higher firm transportation revenues on Roadrunner Gas Transmission Pipeline (Roadrunner)
  • A $3.6 million decrease due primarily to gains on sales of excess natural gas in storage in 2016
  • A $1.4 million increase in operating costs due primarily to higher labor and employee-related costs associated with benefit plans.

 

Q&A from OKE Q3 conference call

Q: What are you expecting for the cash tax rate if nothing changes and how are you thinking about managing coverage going forward if we have to assume that cash taxes were to go up?

Senior Vice President Derek S. Reiners: We will guide to cash taxes for 2017 when we roll out the rest of our guidance maybe later this year or early next year. We do think about and we do forecast cash taxes as we think about distributions. Obviously, we had been running thicker coverage at OKE here in this period of some uncertainty, but as we look forward and think about the dividend growth, we’ll consider the cash taxes as a part of that analysis.

Q: So I really have two questions: one, given all the excitement by the producers, what is the timeframe that we would expect to see you FID that position to spend $100 million in capital and bring that idle plant back? And then secondly, could we actually see new builds of facilities beyond kind of the operating leverage that you just highlighted?

President and CEO Terry K. Spencer: I think we’re seeing tremendous development in the STACK and SCOOP as we speak and it’s still early. Now, this 100,000 barrel a day potential, as we’ve said in the past, is a two to three-year phenomenon. Certainly, at the rate that we’re seeing this development, it could happen earlier, but a two to three-year timeframe I think is an appropriate way to think about it. And as we move into 2017 and we hear more about producers’ plans and as they approve their budgets, we’re going to get a better sense of the SCOOP and STACK and what it will mean to us from a timing standpoint. And we’ll be in a position to better refine that certainly as we move into the first quarter of 2017.

Q: The 150,000 to 200,000 barrels a day that you’re talking about that you’re pulling now from SCOOP/STACK, where is the upside potential there without additional assets on your end? And then you’ve mentioned the 100,000 barrels a day and the minimal capital there. Is there additional capacity within the system as it sits today for Q4, Q1 maybe Q2, just short-term ramps or do we need to see dollars flow that direction to allow additional volumes in the system?

Terry K. Spencer: We do have capacity available today for some of it. I think what we said 40,000 barrels a day today. So, that’s capacity that’s existing naturally in the system. We don’t have to expend any meaningful capital for that. The incremental 60,000 barrels a day that gets you to the 100,000 is where we’d have to spend some capital, and I think that number was on the order of $100 million.

Q: On the natural gas numbers, pulling those down for the year, it seems like the direction we’re heading out to the Q2 results and kind of softness that you guys have targeted for Q3. When we look at the exit rates, you mentioned the multi-pad well delays coming into the fold. Is that the only benefit that we’re getting in Q3 that leads to those higher rates or does higher rates also foreshadow activity increases on top of the delayed connections?

Executive Vice President and COO Kevin L. Burdick: It’s really both. I mean, there have been the delays that have really caused the lower volumes and the lower guidance. Those pads are coming on line. We have seen some of it already completed in October. There are now some more – many additional wells to come on line through the rest of this year, and we’ve also got visibility into early 2016 to expect that ramp to continue on into the early parts of 2016 as well. So, with the producer activity, the ramp that we’ve seen in completions and also some visibility we had in the rigs going forward, that’s what gives us the confidence that that ramp will continue through Q4 and into Q1.

Q: So, I actually wanted to start off on some of the M&A comments or response that you gave to an earlier question. You talked about cash being paid to shield taxes versus giving equity to a potential target. What’s the leverage that you would be willing to go to at the parent in such a scenario?

Derek S. Reiners: I think it depends a bit on the nature of the acquisition and the assets or the businesses within that business. So, if you think about what we’ve been trying to do over time is move more towards fee-based businesses, certainly, the Pipelines business where we’ve got Roadrunner now in service and the WesTex expansion, those are more highly fee-based businesses, perhaps could carry a little bit more leverage than one that’s more volatile. So, I think it would depend a bit on that. What we’ve been targeting at the partnership for leverage is 4 times or less, and we think we’re going to be at 4.2 times or less by the end of this year. So, I don’t think you would expect it to be dramatically higher than what we’re thinking about today.

Q: Following on Jeremy’s question on the M&A front, obviously, you want to have businesses that could potentially integrate with your existing footprint base, I mean, are you looking at any kind of step-out opportunities or something where you think you would like to geographically be in areas where you aren’t currently?

Terry K. Spencer: Most of the potential targets that we think about are do have some overlap within our existing footprint but do modestly reach into some other areas. I think that could make sense for us. Looking at a collection of assets, stand alone, significantly outside our geographically footprint, just buying stuff because you can get it at a good value, certainly doesn’t have much appeal to us, but yeah, modestly outside our footprint could make some sense.

Q: What’s the remaining flared gas capture opportunity in North Dakota look like? How much of a backlog do you think you have there?

Kevin L. Burdick: Yeah, we’re still in that 70 million cubic feet to 80 million cubic feet a day range. We have brought on Bear Creek.  The state reports the flaring a couple of months in arrears. So, we don’t have that data yet to give the exact numbers, but we know the flaring has gone down as Bear Creek has ramped up. We just as recently as last weekend completed the last step of a gathering system expansion that put out some additional flares. So, we’re expecting that run rate maybe to be in the 5% range kind of going forward if we think about our total production and the gas capture we expect going forward.

Q: So, are you still confident – speaking of M&A, about ultimately hitting that 6 times to 8 times EBITDA multiple all in for the West Texas LPG pipeline?

Senior Vice President Sheridan C. Swords: Yeah, we’re still confident. We are out there actively engaged with a lot of potential new processing plants are coming on. So, we’re very excited about the volume growth that we see on the West Texas system. So, we’re very confident about getting to the 6 times to 8 times by 2020.

Q: On this new STACK residue gas pipeline opportunity, is it fair to say that, that ought to be a much better than normal gas pipe EBITDA multiple and how large could it be?

Senior Vice President Phill May: I think it would be probably a good multiple project. It’s at this point just expansion. There may be opportunities to develop more capacity as the open season matures, which may mean that we need to put in some pipe. But yeah, it’s probably 200 million cubic feet to 400 million cubic feet a day, I would say, is the sweet spot for us, and it provides a lot of interconnectivity with interstate pipeline down in West Texas. So, it seems to be a very popular discussion because of the value associated with getting the molecules out there.

 

 

 

 


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