歐尼克 (OKE) 2017 Q3 法說會逐字稿

Good day, and welcome to the Third Quarter 2017 ONEOK Earnings Call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you, and welcome to ONEOK's Third Quarter Earnings Conference Call. 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 any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

Our first speaker 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 are Walt Hulse, Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs; and Kevin Burdick, Executive Vice President and Chief Operating Officer.

Before I hand the call over, I have a few brief opening remarks. I want to start out by saying how much I appreciate the efforts of our employees who personally endured Hurricane Harvey. Employees at our Mont Belvieu area facilities and countless others at our company worked tirelessly to keep our assets running safely in order to provide needed services to our customers. I am very proud of them, and as expected, their dedication and commitment to this company continues to be nothing short of remarkable.

I should also mention that the swift recovery of the Mont Belvieu infrastructure following Harvey would not have been possible without the hard work and cooperation of many of our industry peers, customers, service providers and local governments. Many thanks to them.

I also want to extend our thoughts and prayers to the victims, their families and all affected by the senseless tragedy that occurred in New York City yesterday afternoon. The city and its people will once again prove its courage and resolve as it copes with this tragic event.

Moving on to our third quarter performance. Building off our second quarter results, third quarter performance was strong, benefiting from natural gas and natural gas liquids volume growth and higher transportation revenues in our natural gas pipeline segment. These results demonstrate that we are well on our way to achieving our 2017 guidance.

As we stand today compared to a year ago, rig counts have increased in the states we serve by 70%, driven primarily by technological advances in drilling, which has made exploration more effective, more efficient and production more prolific. We are seeing petrochemical facilities and ethane crackers coming online and expect 2 more to start up in the next several months. The industry has been anticipating these start-ups for several years, and now we're beginning to see real demand for ethane, which Kevin will discuss more in a moment.

We're also hearing from customers about the next wave of petrochemical facilities to be designed and built on the Gulf Coast. I mention this because it's important to point out that the energy industry is once again proving its resiliency and its adaptability to the marketplace. I believe ONEOK has played a big part in that by continuing to invest capital to aggregate supply and deliver it to the markets. We are well positioned to meet the needs of our customers today, and we are committed to continue investing in and around our assets to meet their needs into the future.

With that, I will now turn the call over to Walt.

Thank you, Terry. ONEOK's third quarter adjusted EBITDA was $517 million compared with $462 million in the second quarter 2017, a 12% increase primarily driven by natural gas and natural gas liquids volume growth. As noted in our earnings release, third quarter results included approximately $20 million in noncash impairment charges related to nonstrategic assets and equity investments in our G&P segment, which impacted third quarter earnings per share by $0.03. We estimate that without the disruption of Hurricane Harvey, the NGL segment's earnings would have been approximately $4.5 million higher for the quarter or $0.01 per share.

Last week, we announced our quarterly dividend of $0.745 per share or $2.98 per share on an annualized basis, unchanged from the previous quarter when we increased the dividend by 21%. Dividend coverage was a healthy 1.3x for the quarter. Management still expects to recommend annual dividend increases of approximately 9% to 11% beginning in 2018 and annual dividend coverage of 1.2x or greater.

Since June, we've announced nearly $0.5 billion in attractive, low-multiple growth projects supported by commitments from anchor customers. In September and October, we issued 3.3 million shares through our ATM equity program, resulting in net proceeds of 1 point -- of $184 million. The proceeds of these issuance, along with cash generated in excess of dividends, support these recently announced high-return projects as we prudently manage our balance sheet. We continue to see opportunities to make attractive investments supported by customer commitments. To the extent that we make additional future investments, the ATM will be one of the tools available to fund future growth.

ONEOK's trailing 12-month GAAP debt-to-EBITDA improved again to 4.9x at September 30. Our annualized third quarter GAAP debt-to-EBITDA run rate was 4.6x. We continue to expect leverage to be around our target of 4x or less by late 2018 or early 2019. We continue to proactively manage our balance sheet. We repaid $1 billion in outstanding debt in July and September combined and completed a $1.2 billion senior notes offering in July, essentially extending the term of the debt at a very attractive rate. We are well positioned with ample liquidity to effectively manage our debt maturities and continue to finance growth investments.

As it relates to the review of rates on West Texas LPG, in late September, the administrative law judge provided its findings to the railroad commission of Texas, which the commissioners may accept, modify or remand for further proceedings. There is no deadline for them to take action, but we anticipate the commissioners may consider the findings and any exceptions filed by the parties this December. Regardless of the outcome, we do not expect the railroad commission's decision to have a material impact on our financial results. It will also not impact our current or future negotiated rates on West Texas LPG nor will it hinder our ability to secure new NGL supply from producers and processors as noted by our recently announced -- announcement to expand into the heart of the Delaware Basin.

In yesterday's earnings announcement, we maintained our 2017 guidance outlook, which was updated last quarter, to reflect the completion of the ONEOK and ONEOK Partners merger transaction. We expect to announce 2018 guidance sometime after the first of the year. Please refer to our news release, investor presentation and 10-Q filings for additional details on the quarter.

I'll now turn the call over to Kevin for a closer look at each of our business segments.

Thank you, Walt. Starting with our natural gas liquids segment. Third quarter adjusted EBITDA increased 8% compared with the second quarter 2017, including the impact from Hurricane Harvey, which lowered our EBITDA by approximately $4.5 million. We sustained no significant damage to our facilities but experienced reduced volumes due to industry downtime and increased operating costs following the hurricane. We essentially realized no benefit from optimization directly related to the hurricane. As we look forward, we have seen wider spreads so far early in the fourth quarter.

NGL volumes gathered averaged approximately 812,000 barrels per day, a 5,000 barrel per day increase compared to the second quarter of 2017. Higher Mid-Continent volumes and higher volumes on our West Texas LPG pipeline drove the increase. Volumes on our Bakken NGL Pipeline decreased slightly from the second quarter due primarily to planned maintenance activities at our Garden Creek and Grasslands natural gas processing plants in the Williston Basin and planned maintenance on the Overland Pass Pipeline. As we discussed previously, our Bakken NGL Pipeline can run above its nameplate capacity of 135,000 barrels per day, and through October, volumes had returned to levels at or above what we experienced in the second quarter. We continue monitoring producer customer activity as well as the current utilization of Overland Pass Pipeline and are evaluating our options to provide additional capacity out of the region.

Third quarter NGL volumes fractionated were down slightly compared with the second quarter 2017, primarily impacted by Hurricane Harvey. Volumes that were unable to be fractionated during the third quarter were stored and will be fractionated in either the fourth quarter of 2017 or first quarter 2018. Ethane rejection levels on our NGL system remained relatively unchanged in the third quarter 2017, averaging more than 150,000 barrels per day, similar to second quarter levels. As multiple petrochemical facilities are expected to come online in the next few months, we continue to expect ethane recovery levels will fluctuate in the fourth quarter and into early 2018 as these start-ups occur.

As we have moved into the fourth quarter, we have seen a significant increase in our gathered volumes. In October, we exceeded 900,000 barrels per day on numerous days. The increase is a combination of volume growth from overall raw feed and additional ethane that is being recovered.

For the natural gas gathering and processing segment, third quarter 2017 adjusted EBITDA increased 11% compared with the second quarter 2017, with the segment once again posting solid volume growth in the Williston Basin and STACK and SCOOP areas. In the Williston Basin, volumes processed again established new highs with an average of more than 840 million cubic feet per day during the quarter despite planned maintenance at some of our processing facilities and the maintenance on Overland Pass Pipeline. Mid-Continent volumes averaged more than 740 million cubic feet per day, an 8% increase compared with the second quarter 2017.

Rigs remained steady across our acreage with approximately 30 rigs operating on our dedicated acreage in the Williston Basin and approximately 15 rigs on our dedicated acreage in the STACK and SCOOP areas combined. In the Williston Basin, we connected 130 wells during the third quarter for a total of 313 through the first 9 months of the year, well on our way to completing our target of 400 in 2017. We now estimate that drilled but uncompleted wells on our dedicated acreage increased to between 350 and 400 compared with 300 previously. We continue hearing of improved efficiencies across the basin, including indications of between 10% and 15% productivity improvements in wells completed in 2017 compared with 2016. At current rig activity levels, in addition to DUC inventories in the basin, we expect continued volume growth into 2018.

Growth in the Mid-Continent continues as well. We connected 35 wells in the Mid-Continent during the third quarter and have connected 76 through the first 9 months of the year, well on track to reach our target of 100 by the end of the year. The segment's average fee rate was $0.86 per MMBtu in the third quarter 2017 compared with $0.76 per MMBtu in the third quarter of 2016, a 13% increase which was driven primarily by increased volumes on contracts where we received higher fees. We still expect the segment's average fee rate to be approximately $0.85 for all of 2017.

In the natural gas pipelines segment, adjusted EBITDA increased 8% in the third quarter 2017 and 13% through the first 9 months of the year compared with the same periods in 2016. The segment continues to benefit from higher fee-based earnings and increased transportation capacity contracted. We continue discussions with producers and markets to develop long-term natural gas takeaway solutions across our footprint, especially out of the Permian Basin, where we have had a long-standing asset position with our WesTex pipeline system and, recently, our joint venture Roadrunner pipeline.

As Walt discussed, we've announced nearly $0.5 billion of capital growth projects, with the most recent being the $200 million expansion of the West Texas LPG pipeline into the prolific Delaware Basin, one of the fastest-growing plays in the U.S. The project is supported by long-term dedicated NGL production from 2 third-party natural gas processing plants, which we estimate will produce up to 40,000 barrels per day. The project is expected to be completed in the third quarter of 2018. Fees on this project are negotiated, bundled rates at market-based transportation and fractionation rates.

Because this is an extension and an expansion of an existing pipeline asset, we expect EBITDA multiples to be in the 4 to 6x range, better than our typical 5 to 7x. Additionally, the lateral is sized to allow for future growth beyond the initial 2 plants. We continue to discuss opportunities with numerous customers in the Delaware regarding potential contracts with more than 10 new processing plants in the area.

Terry, that concludes my remarks.

Thanks, Kevin. I have just a couple of closing comments as it relates to our future growth projects before we take your questions.

Following the West Texas LPG expansion announcement, we still continue to develop our unannounced inventory of potential capital growth projects. We've updated that inventory, which is now between $2.5 billion and $3.5 billion compared with $1.5 billion to $2.5 billion previously. This inventory remains heavily focused on NGL infrastructure, which we anticipate could be announced between now and 2020. We are expanding our existing businesses and continuing to focus on deploying capital prudently at attractive returns and in ways that will create value for our customers and investors. Finally, I want to once again thank all of our employees for their continued hard work and their commitment to safe operations, our customers and the communities we operate in.

Operator, we are now ready for questions.

(Operator Instructions) Our first question will come from Shneur Gershuni from UBS.

Just a couple of questions. Just to start off, I was wondering if we can talk about your CapEx funding strategy going forward. You tapped the ATM this past quarter. And I'm trying to understand, is it more because you were during a blackout during the merger process and needed to get leverage in line post close and no longer expect to use it and use retained DCF? Or alternatively, do you continue to fund using the ATM as a primary source of funding?

Well, Shneur, there was no relation to the period of time between the announcement of the merger and the closing of the merger. I think that it's important to note that we've announced this $500 million or so of new growth projects since June, and we wanted to use the ATM to make sure that we funded those because they were in addition to the CapEx that we had previously been discussing. So it was more of a getting ahead of the game and making sure that as we look at forward growth projects, we maintain a very strong balance sheet.

Okay. And then secondly, the $500 million of identified CapEx for 2018, are there any other projects that you're very close to approving or moving forward with that could take the number up materially in 2018? Or is that kind of the run rate we should be thinking about?

Well, I think you should always -- this is Terry, Shneur. I think you should always think about that we've got this base run rate of kind of routine growth, but we're continually working this backlog of new projects. And as contractual commitments and anchor customers come together, certainly, we'll go forward and take those projects to our board. So we've got a number of projects that are in various stages of development. And as those things mature, like we've always said, we'll not only -- once we get those approved by our board, we'll certainly go public with those.

Okay. And final question. You've had this forecast out there for dividend growth around the 10% range for several years going forward. How much capital do you need to be investing in to achieve that growth rate over the next couple of years? Is it a couple hundred million dollars? Is it more than you're running at, less? Just kind of wondering what's the cadence to being able to achieve that growth rate, operating leverage versus needing to invest capital?

Sure, Shneur. This is Walt. The dividend growth rate that was previously announced was supported by base growth CapEx in line with the past couple of years. New projects enhance these cash flows and will produce more free cash flow to reinvest in our business and maintain our strong balance sheet.

(Operator Instructions) We'll take our next question from Jeremy Tonet with JPMorgan.

Terry, just wanted to pick up on one of your last comments there with regards to the upsize in the kind of growth project evaluation list going up to $2.5 billion to $3.5 billion there. I was wondering if you could provide a little bit more color on what specifically is driving that and what's changed. It sounds like this NGL pipeline is a part of the driver there. But is there any more you can share as far as what basins or anything else in the market that's evolved that you guys see as better opportunities now?

Well, so certainly -- Jeremy, at a high level, what we're seeing certainly is core NGL growth in the basins that we operate. Certainly, in the Williston Basin, we continue to grow prospects, as Kevin mentioned on the call -- or on his call remarks, rather. We look great, continue to see strong development in the STACK and SCOOP. And certainly, this recent announcement on West Texas is certainly an indicator of the opportunity that's in front of us there. So the bulk of the CapEx that was -- this increased CapEx in this unannounced backlog is going to be in the NGL segment, and it will be in the form of pipeline loops, pumps, pipeline infrastructure, potentially fractionation capacity. It could be some storage in there possibly. So projects of that nature primarily is what that consists of. Kevin, you got anything you can add to that?

No, just growth off our existing -- significant growth off our existing assets.

That makes sense. And then just another question on funding growth CapEx going forward. There's been kind of an increased use of hybrid securities out there. I'm wondering how you think those stack up versus the ATM when you're looking to minimize dilution for future growth.

Well, of course, we will look at every opportunity that we have to fund the business going forward. We're pleased to be in a position with a very strong investment-grade balance sheet and traditional capital access is something that we enjoy, and will probably be where we would lean more towards. But we'll stay atop and apprise of everything that's in the marketplace and evaluate whether they fit into our cap structure or not.

Got you. And then just looking at the STACK and the SCOOP. I was just wondering if you could talk a little bit more about the dynamics there. It seems like STACK continues to have good opportunities moving forward with Canadian Valley there. And Knox seems like it's still on the back burner at this point. I was wondering if you could share any more on what you see there.

Sure. Kevin can help you there.

Yes, Jeremy. Again, we're excited by the STACK and the SCOOP, and I think our volume growth sequential quarter-to-quarter just shows that and just demonstrates some of the potential. On the G&P side, we do have the 200 million a day offload that we've got out there. That's expected to be complete by the end of the year. So that's the first tranche of capacity. Then we've also got the Canadian Valley 2 expansion, which we have announced. And beyond that, our NGL segment with the footprint we've got in the STACK, in the SCOOP there, there's a lot of other additional plants. I think EnLink just came out yesterday and announced a new plant that would be under our contract with them. So a lot of activity going on in the STACK and the SCOOP. Producers have come out here at just the last couple of calls I've seen and talked about moving to full -- kind of the full development program, which just drives the efficiency of the rigs up. And so there's a lot of opportunity for us given our footprint in the STACK.

And then just a last one on the Bakken. On the processing side there, just wondering if you could update us on the competitive dynamics. You've seen some other MLPs moving forward with processing expansion, such as Bearden and others. And I was just wondering if you could give us your latest thoughts there.

With the volumes that we have seen in the Williston, we probably -- especially as we moved into the third quarter and gotten past some of this maintenance, we're probably -- excuse me, into the fourth quarter and gotten past some of the maintenance, we probably have 125 million a day of capacity left. So with the rig activity we're seeing and the well performance that we're seeing, then clearly, you -- we could see additional processing capacity that we would need.

And our next question will come from Eric Genco with Citi.

I was just wondering what you've been hearing from producer customers in the Williston kind of heading into next year in terms of rig counts and activity. You're targeting about 400 wells this year, and the 30 rigs, it seems like that's about 27 days to complete a well, which seems high. So do you expect the rig counts to taper off? And if nothing changes, is 400 a conservative number going forward? Or how do you think about all that?

Eric, this is Kevin. I'll make -- I got some thoughts, and Mike Fitzgibbons may have a couple thoughts as well. Our conversations with the producer customers continue to be very positive. The rig counts have held in, and we've seen some price strength here over the last few weeks. We see no indications that those rigs are going to back off. So yes, if you maintain this activity level at 30 rigs, the 400 would be light as we think about 2018. Not ready to get out there with the guidance yet. We'll do that as we release our financial guidance. But clearly, you're right, the 27 is high, and so we would expect the well connects to go up in '18. Mike, do you have any...

No, I agree with that. The only thing I'll add is we've had a couple of producers announce they can achieve their volume growth targets with less rigs because of the efficiency increases. So we may see a rig or 2 drop, but we are still seeing very productive wells and are forecasting volume growth from those rigs.

Great. And just one quick follow-up. I'm curious, as you look out at -- and I think it's been sort of asked from a couple of different angles, but you got the $485 million to $495 million of projects since June and $40 million that is finished in 2017. So I guess the rest is overwhelmingly in '18. Do you expect your overall debt balance -- your net debt balance today -- or at quarter-end was around $9.5 billion. Do you expect that to drop? Or do you -- meaningfully at all? Or do you think it hangs in there or maybe drifts up a little as you have the EBITDA growth that sort of gets you to your leverage target?

Well, we're not going to give specific guidance to '18. But I would say that we do expect to have significant EBITDA growth that will help those leverage statistics along in the most dramatic fashion.

Okay. So the $9.5 billion of net debt, is that -- do you see it materially dropping over the course of next year or no?

I think given the level of our CapEx, we'd expect to see our deleveraging come more from the increase in EBITDA than a drop in debt.

And our next question will come from Danilo Juvane with BMO Capital.

I was looking at the -- I wanted to go back to 2017 guidance, the G&P segment specifically. The way -- how strongly you guys have performed this year would imply a decline in 4Q just to get to the high end of the guidance range there. So it seems that you're being a little bit conservative by not raising guidance in my opinion. Is there any other offsets that we should be thinking about, whether they be related to Harvey or maybe some of the ethane volumes that you have baked into your forecast that're going to be late -- because of the petchem outages in the Gulf Coast?

No. I mean, specific to your question about G&P, yes, when you do that math, that's where you get to. The one dynamic that we always at least consider as we're thinking about the fourth quarter for gathering and processing is weather. Especially when you look at the month of December, we do historically see a little bit of a pullback of our volumes. So we do factor that in. I don't think we see any lingering effects related to Harvey from our business. As we've talked about, we've seen transitioning a little bit just overall. We talked about the volume growth we have seen in October in our NGL segment. Clearly, a decent chunk of that volume growth would be ethane, which would send a signal that the ethane recovery story is starting a little bit. So that's -- I mean that's how I would frame up kind of how we're thinking about guidance and still holding that firm.

And then with respect to growth CapEx, I think the previous guidance was $500 million for the year. Thus far, we've hit, I think, $250 million. So should we expect a big chunk in 4Q here? Or is that going to extend over into 2018?

Yes. We will -- I mean, yes, with the recent announcements, obviously, we're getting -- we're hot and heavy into the construction on those projects that we've announced. So you would see that capital ramp up in Q4.

And our next question will come from Brian Zarahn with Mizuho.

On the West Texas expansion project, could you elaborate a bit on the volume assumptions and your 4 to 6x multiple expectation?

Sure. As we think about those up to 40,000 barrels a day that goes in service on the back half of 2018, we would expect that volume to ramp up maybe over a year to 2 past the in-service date. I mean, Sheridan...

Exactly right. Yes, within 2 years, we should be at or above the 40,000.

Okay. So the 4 to 6x multiple, it seems, is around 40,000 barrels a day of volume?

Yes.

Okay. And then on those new barrels, what type of fractionation opportunities are there potentially? Or would those go to third parties?

Well, the 40,000 that we referenced in the press release, we do have a bundled service with them. We will be fracking those barrels. So it's a total package deal for us. The pipeline does give us the opportunity to talk to more people to bring more volume on that and fractionate it as well at or below multiples that we'll see on this project.

Okay. So just to summarize, the 4 to 6x multiple expectation seems about 40,000 barrels a day of volumes, including fractionation fees.

Yes.

Yes.

Okay, that's helpful. And then, obviously, of excess capacity, how do you view the competitive landscape in the Permian for NGL takeaway to increase the utilization of the extension?

Brian, this is Sheridan. It's a very competitive landscape out there. But as we've said before, with having an existing pipeline that we can incrementally add capacity to it to dial into what the customer actually needs. We can do it much cheaper and faster than other pipelines, brand-new pipelines that are coming in there. So we see ourselves being very competitive. And with this new expansion in here, we get this -- us into a position that we can compete even better for this Delaware barrels. And we have been talking to multiple producers and processors out there in the short term right before we announced this and after we announced this, we've even had more come to us and want to get on this pipeline, want to talk to us about it. So we're very excited what this bring to us and very excited about seeing more expansions come out.

We'll stay tuned for updates on the extension. So obviously, a lot of focus on your organic opportunity set. As we move into 2018, how do you view M&A playing overall in your growth?

Well, certainly in our thinking, we don't have any M&A factored in, but we're always going to be thinking about those opportunities. And certainly, we've got a strong currency to work with. Certainly, it's a financially sound company. But I can tell you what our focus will be heavily organic, and any M&A, whether it's a bolt-on asset or whether it's something even broader from a strategic perspective, will certainly just be an opportunistic approach. So heavy organic will be the key strategy and key focus for 2018.

And our next question will come from Michael Blum with Wells Fargo.

West -- just one more question on West Texas, the new pipeline project. I think you mentioned you'll also be expanding the existing system. How much -- if that's correct, how much are you also expanding that by?

Michael, we're expanding by the equivalent amount of 40,000.

Okay. So I guess, since the extension line is 110,000, as you move above that 40,000 on the extension line, does that imply that you'll have to then probably further expand the main line? And I guess, what is the capability to do that?

Michael, you're exactly right that you will have to continue to expand the main line. That's when we get into -- we can expand and spend that capital on the main line as we get the commitments on the lateral coming in there. So we don't have the spend it all upfront. We can incrementalize that capital in there. And as I said, we expect those projects that we're working on now to expand the main line to bring more volume in on the lateral will be in -- at or better than the 4 to 6x that the original one is. We did put some upfront capital in there to put a bigger piece of pipe in the ground so that we are better able to compete in the Delaware.

Okay. And then my other question was just on the cadence of dividend increases as we go out in time. Are you planning to do basically like a one dividend increase per year? Or are you planning to do every quarter? What's the thought there?

Well, Michael, we -- obviously, the board will address that on a quarterly basis. But our expectation would be to be in line with our past practice and most likely look at that quarterly. And the board will evaluate the facts and circumstances each quarter and then act accordingly.

And our next question will come from Tom Abrams with Morgan Stanley.

What's left here? G&P, strong margins in the quarter. Can you just break that down a little bit on how much you might attribute to NGL prices and spreads versus fees?

Tom, this is Kevin. Yes, it's -- again, we've converted so much of our -- through the contract restructuring, we've moved so much of the commodity exposure to fee. It is primarily fee. And when you combine that with our hedged position for 2017, virtually all that is just volume growth with the fee increase.

Good. And then on the distribution, last question. Not so much for '18 but more for '19, just the philosophy around issuing equity to make a 10%-or-so distribution growth when you want to strengthen your balance sheet. Your capital spending is clearly very strong, and the industry itself seems to be moving more toward that mid-single-digit type being acceptable for the larger companies. Just wondering how you've traded off those kinds of dynamics.

Well, we're in a position today where, in this particular quarter, we covered the dividend by 1.3x, and we expect to have significant dividend coverage going forward, which will give us a lot of excess cash flow to put back into the business and reinvest in the business. We -- as I've said previously, the dividend growth that we had previously guided to was based on kind of the run-rate dividend -- or run-rate CapEx that we've been spending over the last couple of years. So as we have this low-multiple projects, we just expect to have even more cash flow to invest in the business going forward.

And our next question will come from Christine Cho with Barclays.

I just have a couple of operational questions. The Bakken G&P volumes were up but the NGL pipeline volumes were down sequentially. What went on there? Was it just more ethane that was rejected versus last quarter?

Yes, Christine. That was primarily around ethane, and it also relates to the maintenance activities that we saw at our assets and how we had to move gas around. And to continue to process as much of the gas as we possibly could, we did end up rejecting more ethane than we had the previous quarter. In addition to that, some other -- another dynamic that was going on during the same time is our de-ethanizer at Stateline really ramped up during that time period. So the NGLs produced actually went up, but yet the NGLs we were pushing down the pipe went down a little bit.

So if the NGL volumes were up but the pipeline volumes were down, like where did the incremental NGLs go? Do you guys have storage up there?

No. It was -- again, it was primarily ethane that was rejected due to a lot of the maintenance and other activities that were going on. And then the ethane that's going through the de-ethanizer does end up in markets in Canada as well.

Okay. And then in your prepared remarks, you alluded to evaluating opportunities for providing additional takeaway out of the Bakken. Your 10-Q says that you're expecting to add capacity to the Bakken NGL line by third quarter of next year. And if you do that, don't you have to expand Overland Pass? I thought that was full. Or is there other alternatives?

Christine, this is Sheridan. Yes, as -- we are looking at the total system, both Overland Pass and Bakken Pipeline, to look at all alternatives to expand it. But you are correct, Overland Pass is full. So any expansion on the Bakken Pipeline will have to take into account takeaway from the bottom end, and we're looking at all options to expand that system as we continue to see the robust growth in the Williston.

And that would have to be looping, I'm assuming.

There's a lot of different options there. It could be looping of the existing system or a completely new system.

I see, okay. And then with natural gas production increasing out of the Bakken, is the incremental residue gas still going down Northern Border? Or do you guys have an idea of how much of the gas is going to AECO?

Well, again, all the -- physically, all the gas out of the basin is -- virtually all of it is ultimately ending up on Northern Border that ends up in the Mid-Continent, the upper Midwest markets. So how it gets priced is really a separate -- from an AECO perspective, it's really a little bit -- it's a different question. But all the gas -- and we're confident that with the growth projections we see out there, that we will continue to be able to move all the residue out of the region on Border.

And our next question will come from Ted Durbin with Goldman Sachs.

I just wanted to verify. I think in your prepared remarks, you said your NGL gathering volumes are up to 900,000 barrels a day in October. Is that right?

That's correct.

So that's a big pickup versus what you did in third quarter. What's the driver there? And can you give us a breakdown of whether it's mostly Mid-Con? Or which region is that coming out of?

Well, we're really seeing an increase in all of our regions. We talked about the Bakken barrels being down, and now we're back up to those levels before. Mid-Continent volumes are up as well. A chunk of that is going to be ethane as we have seen ethane recovery pick up during the month of October. We still think that will fluctuate a little bit as these new petchems come online and go through the start-up. But again, we've seen some nice volume growth out of all the areas.

And is it fair to say the margins on that additional will be in line with sort of your rules of thumb, the $0.30, the $0.09 and the $0.04 -- or $0.03?

Yes. This is Sheridan. Yes, they'll be close. We -- typically, we have a little bit of a breakdown for ethane, a little bit of an incentive. But it's going to be materially in the line of what we've given. And remember, a lot of the ethane that's probably coming on is going to be a Belvieu-based barrel coming out of Mid-Continent, which will be at a higher than the average rate that we have in our presentation because that has both Conway and Belvieu, and then we talked about the Mid-Continent. So we'll probably be just slightly higher than that.

So Sheridan, it's fair to say that in many of your contracts, you have a tiered structure, a slightly lower transportation and frac rate for ethane versus your propane plus. Is that correct?

That is exactly right. But we expect the Belvieu barrels to come out first, which would be higher than the Conway price barrels.

Great. Okay, that makes a lot of sense. That's really helpful. And then can you talk about the overall returns -- I guess, blended returns both on the, let's call it, the $500 million of growth CapEx you've announced since June and then as we think about that bigger chunk, the $2.5 billion to $3.5 billion, what kind of EBITDA multiples should we think about for both of those buckets, please?

Well, I think you're going to see -- a lot of those projects in that unannounced backlog are going to be similar to the routine growth that we've seen historically. So you could see a good chunk of this coming in at 4 to 6x. But I think broadly speaking, overall, some of the larger infrastructure projects that are in that mix are going to be in the 5 to 7x that we've historically indicated. Did that help you?

Yes, that's helpful. And then last one for me. Just operating cost looks like they're up a decent amount here in third quarter sort of year-over-year. Is it all just sort of new assets? It sounds like there were some hurricane costs in there. What sort of -- is this a good new run rate on op costs? Or is there anything -- any kind of onetime items in there?

Yes. The op costs are really just more of our growth and dealing with that. Yes, there was a little bit in there for the hurricane. But again, every quarter, you typically will see some onetime attributes. But I think that'd be probably be a decent run rate as we think about going forward.

And our next question will come from Craig Shere with Tuohy Brothers .

October saw another even larger stair step up in the Conway-to-Mont Belvieu basis. How sustainable do you see this? And could this trend combined with your dividend coverage mitigate the need to hit the ATM as more projects are announced?

Well, as we -- I mean, yes, Craig, you're right. We have seen an increase in spreads through the month of October. We do think there's some likelihood that those will kind of maintain for 2 or 3 months here or beyond that. On the flip side, as our volumes do increase, that will reduce a little bit the amount of volume we can actually move on the pipes as we physically are flowing more volume on our assets. So there's a little bit of a give and take there. But yes, it's nice to have that tailwind of the stronger spreads. Sheridan?

Yes, I definitely agree. And you're very right, as more of this ethane that we talked about and more volume growth, we will consume more of the pipeline for fee-based business, and that will leave less capacity for optimization activities.

Understood. And with respect to the $200 million West Texas LPG expansion, I guess, $160 million net to OKE. I think, 3 years ago, the guidance was given that you were hoping to achieve -- on the original acquisition and follow-on business, including maybe $500 million of expected growth CapEx, you're expecting to achieve an all-in 6 to 8x multiple by the end of the decade. It seems like maybe the growth CapEx figure is coming well under the $500 million you all envisioned years ago. Do you see that, due to efficiencies, that the EBITDA expectation would be intact? Or how do you see that multiple playing out over time?

Craig, I still think we will still reach that by the end of the decade as we go up there -- especially as we look at all the projects and all the plants that we're looking at right now and how that kind of evolves. We knew it would take us some time when we bought the assets to get our strategy in place because a lot of the plants that were coming on when we first bought the assets were already committed. So we knew we had to wait for the second wave of gas plants that are being built that were not committed, and that's where we are right now. And we're finding that we can very effectively compete for these gas plants. And so I still think that we will reach that 6 to 8x by the end of the decade.

Okay. And one last follow-on. I was under the impression that that original guidance did not incorporate any additional upside from associated fractionation. Does that continue to be the case? And does the 4 to 6x for the $200 million project include or exclude related fractionation?

Well, you've got to look at fractionation as -- our fractionation system pulls from all across our assets and then we see it growing through the whole thing. So it all depends on when those -- that fractionation capacity is needed. And as we keep growing like this, as Terry mentioned, we will probably end up having to build more fractionation capacity. And we will see the Permian as being able to help support that growth, and we will get market rates for that.

But does that feed into the original multiple expectation for the West Texas acquisition you originally made?

The original -- when we did that originally, it was more based on just pure tariffs and not the fractionation fees.

And our next question will come from Chris Sighinolfi with Jefferies.

A lot has been asked and answered so appreciate all the color. I just have 2 follow-ups. They're more sort of on structure. I was just curious, Bakken has done quite well this year. Obviously, the DAPL pipeline was sitting out there for a long time, had sort a of story -- history to get into service. But now that it is, we see [clear book] pricing at a premium. Just wondering, your conversation with producer counterparts up out there, how much, the pipeline actually being in place and the pricing dynamic, if at all, is shaping decisions. And how long they might -- how they see that, I guess, evolving over time?

Yes. I mean, obviously, with DAPL, it -- clearly, anytime we can provide more pipeline takeaway capacity for crude, it benefits the producers from a reliability perspective and also just a netback perspective. I mean, we typically hear that their netbacks are maybe $2, $3 better than they were before DAPL. So that's just increased strength and helping their cash flow to fund more drilling.

Certainly, operational reliability has to have improved significantly.

Absolutely. I mean, you can look at some of the state data, and rail has really taken a downward trend. So that -- clearly, the pipe is going to be more reliable than rail.

Okay, that's helpful. And then, I guess, switching gears, probably for Sheridan. Just this is a question to which I'll plead ignorance. What is your expectation or have you guys looked at what happens with ethylene, polyethylene markets when we bring on this much steam cracking capacity in a narrow window of time? I'm kind of blind what happens further downstream, and so I'm just wondering if you can help us think about the effects of that and maybe what your petchem customers are saying and thinking about it and if there's an opportunity for you to participate at all on that end of it.

Yes. What I would tell you on what we look at, right, and we hear from our customers on the polyethylene market is I think that these crackers are going to make ethylene but you're already seeing these companies bring on ethylene to polyethylene units. So you're really talking about where the ethylene is going. And worldwide, with the low cost of feedstocks that we have in the United States, they're all saying we, the united -- the Gulf Coast crackers are much further to the left on the supply stack. So if we would overbuild and the world cannot consume that much polyethylene, you will see more the naphtha crackers and more Far East crackers being shut down, maybe some European crackers. A long time before you see the Gulf Coast crackers shut down. So -- but that's why everybody -- that's why you're seeing the next wave of crackers being talked about on the Gulf Coast because this is the most advantaged place today to build crackers due to the cost of feedstocks.

So the multiyear view then is -- if I were to paraphrase it, is something similar to what we've seen with other hydrocarbons where U.S. market simply because of its advantaged cost structure, pushes out higher-cost supply globally. And so we're basically going to make inroads via export. That's the expectation?

That's right. You're exactly right.

And if I could -- I don't know if you know the answer, but are there particular foreign markets we could pay attention to, to maybe get a sense of where -- from where that demand or where that supply competition is going to be most -- I guess, most severe?

Well, I think from a demand side, you're going to see the growth from China and India. We also see some from Latin America and maybe a little bit from Europe. But China and India are going to be the big movers on the demand side. Competition -- okay?

No, no. I didn't mean to cut you off, Sheridan.

You said on the competition for supply, I think that's a big -- the only thing that's going to affect that is the gas-to-oil ratio. If you would see oil and gas on a Btu basis come back closer together, and naphtha would become more advantaged. You may see -- that's, I think, what you would see on supply. We are seeing -- and it depends on how you look at supply competition. Obviously, we are exporting propane and ethane, which are going to crackers that would compete against polyethylene -- against our polyethylene that's being produced in the United States, but that's still pulling the hydrocarbon through our system and out of the United States.

Right, right. And so I guess, the next wave -- I guess this is the interesting question for me, is that if we're seeing the next wave of petchem crackers at least talked about to be built domestically, it would seem like that community is making a determination that the facility better exists here than to export the ethane to whatever form [market will crack it] there. Is that -- I guess, is that fair? Or is there something about the nature of all this that I don't understand.

I think it's a combination you're seeing. Where we're seeing most of the people that want to export ethane for cracking or even propane for cracking are really in India and China, and I think they want to build their own facilities over there and get advantage of the cheap feedstock from the United States. The big -- the people that are building the next wave of crackers are the ones who built the first wave. They're going to be -- obviously, you already heard about the Exxon Mobil-SABIC cracker down at Corpus Christi that's been announced. There's an -- all the other people are also talking about when do they build their next cracker, and all of them are saying it's probably going to be in the Gulf Coast.

Okay, great. I know unrelated to third quarter, but it's always helpful to get your thoughts on market structure over time. So appreciate it.

And that does concludes today's question-and-answer session. At this time, I will turn the conference back to management for any additional or closing remarks.

Okay. Well, thank you, everyone. Our quiet period for the fourth quarter starts when we close our books in early January and extends until earnings are released after the market closes in late February. Have a great rest of your day.

Ladies and gentlemen, this does conclude today's conference. Thank you all for your participation. You may now disconnect.