歐尼克 (OKE) 2017 Q2 法說會逐字稿

Good day, everyone, and welcome to the Second Quarter 2017 ONEOK Earnings Call. Today's call is being recorded. And at this time, I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you, Vicky, and good morning, everyone. And welcome to ONEOK's Second 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. I'd like to start by welcoming Andrew back to the team and I also want to acknowledge T.D. Eureste for his many contributions to our Investor Relations efforts during some of the most challenging times over the last few years. T.D. is now Vice President of our Treasury team.

Joining me today on this 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.

Our second quarter ended with the completion of the ONEOK and ONEOK Partners merger transaction, which included the acquisition of all of the common units of ONEOK Partners we did not previously own. ONEOK is even better positioned to execute our long-term growth strategy for the benefit of both our legacy and new ONEOK shareholders. We have many opportunities for organic growth across our businesses through our diversified and integrated midstream asset footprint in some of the nation's most active shale plays. We can provide our current and new customers with full service midstream capabilities. As I've said before, growth opportunities continue to develop in the areas we operate.

Our second quarter 2017 financial results were solid, with volume growth in both our gathering & processing and natural gas liquids segments. Higher average fee rates in our G&P segment and higher transportation revenues from completed expansions in our natural gas pipelines segment. Walt will review our financial results and provide additional color on our 2017 guidance, which was updated to reflect the merger transaction and our business outlook for the rest of 2017. Kevin will discuss our operational results in more detail as well.

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

Thank you, Terry. ONEOK reported strong financial results for the quarter, including healthy dividend coverage of approximately 1.5x for both the second quarter and through the first half of 2017. As noted in our earnings release, second quarter results included approximately $43 million in onetime and transaction-related charges, which impacted second quarter earnings per share by $0.12 per share and dividend coverage by 0.18x. Last week, we increased our quarterly dividend by 21% to $0.745 or $2.98 per share on an annualized basis.

The successful completion of the ONEOK and ONEOK Partners merger transaction, combined with the proactive steps we've taken to improve our leverage position and balance sheet, are being recognized. In July, ONEOK received credit rating upgrades to investment grade from both S&P and Moody's. Both agencies also have established stable outlooks on the company.

ONEOK's trailing 12-month GAAP net debt to EBITDA was 5x at June 30, including transaction costs, 4.9x without the transaction costs. We continue to expect to reduce leverage to our target of 4x or less by late 2018 or early 2019, primarily driven by expected growth of adjusted EBITDA.

In July, we took additional proactive steps to manage our future debt maturities and liquidity by utilizing ONEOK's cash on hand to immediately reduce commercial paper borrowings, completing a $1.2 billion senior notes offering, redeeming all $87 million of our 6.5% senior notes due 2028 and repaying $500 million of our $1 billion term loan due 2019. As a result, we now have nearly $2.2 billion of available capacity on our $2.5 billion credit facility.

2017 guidance has been updated to reflect the June 30 close of the merger transaction with the only adjustment to the midpoint of adjusted EBITDA being the impact of transaction expenses. Our original guidance provided on February 1 did not include the onetime or transaction-related charges I mentioned earlier. And the original guidance also assumed a January 1 transaction closing date.

We narrowed ONEOK's adjusted EBITDA guidance to a range of $1.89 billion to $2.06 billion, and increased our growth capital expenditure range by approximately $70 million to reflect recently announced projects. Please refer to our news release, investor presentation and the 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.

Thanks, Walt. Starting with our natural gas liquids segment. NGL volumes gathered averaged approximately 807,000 barrels per day, a 6% increase compared with the first quarter 2017; and NGLs fractionated increased 8% compared with the first quarter. Bakken NGL Pipeline volumes were up 8%, averaging 141,000 barrels per day in the second quarter. NGL volumes gathered from the STACK and SCOOP areas of the Mid-Continent and out of the Permian Basin also increased during the second quarter. Mid-Continent volumes increased 4% and volumes on our West Texas LPG pipeline increased 7% compared with the first quarter 2017. The Permian Basin remains one of the most active basins in the country, and we continue to have promising discussions with producers and processors in both the Midland and Delaware basins to expand our West Texas LPG system to capture expected production growth.

We connected 2 additional third-party natural gas processing plants during the quarter, both in the Mid-Continent, in addition to the 3 plants connected in the first quarter of 2017. And we have already connected 1 additional third-party plant in the Permian Basin in the third quarter. The total combined NGL production of these 6 new plants is expected to ramp to approximately 30,000 barrels per day by the end of 2017 and increase to more than 40,000 barrels per day in 2018.

Ethane rejection levels on our NGL system remained relatively unchanged in the second quarter 2017, averaging more than 150,000 barrels per day, similar to first quarter levels. We continue to expect an increase in ethane recovery on our system through the remainder of the year as new petrochemical plants are completed.

For the natural gas gathering and processing segment, second quarter 2017 adjusted EBITDA increased 23% compared with the first quarter 2017, primarily driven by volume growth in the Williston Basin and STACK and SCOOP areas. The segment's average fee rate was $0.87 per MMBtu in the second quarter 2017 compared with $0.76 per MMBtu in the second quarter of 2016, a 14% increase which was driven by increased volumes on higher fee contracts in the Williston Basin. We expect the segment's average fee rate to be closer to $0.85 for all of 2017 as our volume mix shifts across regions and contracts depending on producer activity.

We achieved our highest level of volumes processed in the Williston Basin during the second quarter with volumes averaging more than 820 million cubic feet per day, a 13% increase compared with the first quarter 2017. Mid-Continent volumes averaged more than 690 million cubic feet per day, a 4% increase during the quarter.

Despite commodity price fluctuations during the quarter, drilling rigs have remained steady. We currently have more than 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. In the Williston Basin, we connected 108 wells during the second quarter. We expect to connect 400 wells in the basin this year and estimate there are still approximately 300 drilled but uncompleted wells on our dedicated acreage. With this new production that has recently come online, our available processing capacity is now approximately 150 million cubic feet per day in the Williston Basin.

Growth in the Mid-Continent continues to be driven by increased activity and strong production results from our customers in the STACK and SCOOP. Recent activity levels and production results continue to exceed expectations. We connected 27 wells in the Mid-Continent during the second quarter and we expect to connect approximately 100 wells on our dedicated acreage in the Mid-Continent in 2017 as our volume ramp is expected to be weighted more towards the second half of the year.

In the natural gas pipelines segment, second quarter 2017 adjusted EBITDA increased 18% compared with the same period in 2016. The segment continues to benefit from higher fee-based earnings driven by increased firm contracted capacity in connection with the expansions of our West Texas transmission pipeline and our Permian Basin joint venture Roadrunner pipeline, which were both completed in October 2016.

In our earnings release, we provided updated segment-specific guidance and volume expectations. Overall, we've increased adjusted EBITDA for our natural gas gathering and processing, and natural gas pipeline segments and increased our G&P volume outlook. These increases were primarily driven by higher-than-projected volumes in the Williston Basin in STACK and SCOOP areas, and our expectation that drilling and completion activity will remain strong through the second half of the year based on recent discussions with our producer customers. We narrowed our adjusted EBITDA guidance in the natural gas liquids segment reflecting adjustments for the timing of the expected volume increases from recently connected third-party plants.

In mid-June, we announced NGL and natural gas-related expansion projects totaling approximately $170 million to accommodate growth in the STACK area. Projects include a 60,000-barrel per day expansion of our Sterling III NGL pipeline, increasing its capacity to 250,000 barrels per day; and additional NGL gathering system expansions in the area, which are all backed by a long-term contract and plant dedications. These expansions are expected to be complete by the end of 2018.

Additionally, we announced the construction of a 30-mile natural gas pipeline through the heart of the STACK to connect with an existing third-party natural gas processing plant in Oklahoma, which will provide us access to an additional 200 million cubic feet per day of capacity and is expected to be in service by the end of 2017.

And most recently, on Monday, we announced plans to expand our Canadian Valley natural gas processing facility in the STACK area of Western Oklahoma. The project will increase capacity at the facility to 400 million cubic feet per day from 200 million cubic feet per day and is expected to be complete by the end of 2018. It also will provide approximately 20,000 barrels per day of additional volume into our NGL gathering system. Combined with the third-party processing agreement I just mentioned, this plant will bring our total Oklahoma processing capacity to 1.1 billion cubic feet per day. The additional capacity is needed to support the rapidly growing production in the area and is backed by more than 200,000 acres of dedication, primarily fee-based contracts and minimum volume commitments.

Terry, that concludes my remarks.

Thanks, Kevin. A couple of final comments as it relates to our future growth projects before we take your questions. We continue to grow our backlog of potential capital growth projects that we are working hard to develop and earn customer commitments. Once we do so, we will certainly announce those projects. Additionally, I'm confident that over time, we will add to our backlog as we have done in the past. We expect to continue to grow in our existing businesses and continue to focus on applying our core capabilities to create value for our customers and investors.

Finally, I want to thank our employees for their continued hard work, dedication and commitment in operating our systems safely, reliably and environmentally responsibly every day.

Operator, we're now ready for your questions.

(Operator Instructions) And we will take our first question today from Shneur Gershuni with UBS.

Just 2 questions here. The first one is with respect to guidance, I was wondering if you can square something for me. I recognize that you raised guidance at the operational level because of Bakken volumes. However, when I look at the kind of the midpoint, it doesn't suggest a surge in volumes. But at the same time, I look at your performance, I look at comments from E&P producers, it seems like your volume guidance should have been a little bit higher in the Bakken. Is there a hint of conservatism there or was there a bottleneck that we should be thinking about?

And then staying on the guidance question, the NGL segment downward revision sounds like it's a delay in some revs by producer. Is that just shifting earnings into next year? I was just wondering if you could give a little bit of color about that as well.

Yes, this is Kevin. I'll take the G&P question first. No, I don't know that we believe there's conservatism built into our volume guidance for -- that we provided. One thing, when we think about the Williston and to me, you do the math, we are showing that we're going to need to grow in Q3 and Q4 to meet the midpoint of the processed volume guidance. The other dynamic going on there, especially with the Williston, is winter. So we have to -- we learned from January -- last January and February that we do have a little bit of winter weather factor built into that guidance as well. As we look from an NGL, could you repeat the question on the NGL side again?

On the NGL thing, I was wondering if you could give us a little more color as to why the revision's there. Is it something that rolls into '18? Or how should we think about that?

Yes. The downward revision, the small revision to our volumes and the EBITDA in the NGL segment was related to timing. We clearly don't see that as a change in our point of view on the activity levels. It literally was just as the specific timing, the plants came online and how the volumes then are ramping. So yes, it would be -- we don't necessarily see our exit rates changing, it was more a factor of when they came online and how that played into the full year average.

Okay. And then a final bigger picture question. When I sort of look at ONEOK's earnings performance and CapEx spend over the last 2 years, relative to your peers, your capital investment intensity has been fairly low. I do recognize that you haven't announced capital investments, but relatively speaking versus your earnings growth, which has been much higher than your CapEx expense.

Are there more opportunities to continue growing your business while keeping your capital intensity on the lower side? I suspect you've done some off-take agreements and asset optimizations. But is that largely done, and future growth will have a corresponding 1 for 1 investment in CapEx? Or are there more opportunities to continue growing earnings without the same intensity on CapEx that we see in some peers?

Shneur, let me make a couple comments and then if Kevin's got something to add, he can follow up. We do have some more opportunity in terms of taking advantage of the headroom that we have in our businesses. That will kind of come and go, and we will kind of work those opportunities just depending upon what's out there in terms of the G&P landscape. So that will be a bit of a moving target, but we think there's more opportunity to do that.

But I think just fundamentally speaking, we are going to see more capital spend going forward than we've seen from our traditional run rates over the last couple years, just based upon the fundamentals that we're seeing, the strong rig counts that we're seeing right underneath our noses. So I do expect that run rate to increase as we continue to develop those projects and those projects that hit the full menu of services that we provide, NGLs, G&P, fractionation and what have you. So as those come together and materialize, we'll adjust our backlog of unannounced growth projects appropriately and certainly, we'll provide you more color, as we move forward. Kevin, anything to add to that?

We'll now go to Eric Genco with Citi.

I guess just kind of touching on the last question a bit. But in terms of the extension of Canadian Valley, you're getting 200 MMcf a day for $145 million to $155 million. I'm just thinking back to the -- before the commodity price collapse of 2015, you had plans for the Knox plant, 200 MMcf a day again but for $365 million to $470 million. So from a cost per capacity standpoint, this is clearly better.

My question is, why not choose to expand Canadian Valley in the first place over Knox a few years ago? And then is there something that's changed perhaps in the location of where Knox is going to go that makes it less necessary? Or is there a potential to revive that plant? How should we think about all that?

Hi, Eric, this is Kevin. Yes, there's a variety of things I think that are going on with that delta. Sorry, we had some weird feedback here. First I'd say, yes, when we announced Knox, it was a completely different business environment at that point. I mean it was the heyday of the growth. And so that drove -- costs for materials and services were higher. The second thing is the rationale for the Knox location was at that point in time, the SCOOP was really the hot play and that's where the majority of the activity was, and Knox is geographically right in the heart of the SCOOP.

And then, so as the drilling activity shifted a little bit to the north and the STACK became really a prolific play, we started taking a look and that's where our volumes were going to show up. And, therefore, being able to leverage the facility, existing facilities at the Canadian Valley site became the appropriate place to put that next tranche of capacity we were bringing online. That also had an indirect effect of the gas coming on in the STACK, where we had a significant amount of infrastructure already in place, so that also drove down the field infrastructure necessary for the plant as well. So a combination of all those factors. We still have -- as the STACK matures, we still have the ability, we could put another train at that same facility. If the SCOOP continues to evolve, that wouldn't preclude us from putting another plant down at the Knox site that we've referred to previously.

Okay, that's very helpful. And then just real quick on the NGL segment, you showed an 11% increase sequentially in operating cost versus 6% in volumes, and you talked about your ability last quarter to run the Bakken NGL line above nameplate and this quarter you definitely did. Did that cost you on the operating expense front? Or is there something else going on there? And what is the status of the pipeline expansion there? It's -- is 3Q '18 still a good target? Could it come on earlier, would it be good if it did? Just want to get your thoughts on capacity there and possible expansions beyond the 160.

Yes. I'll start from a cost standpoint, no, there was no relationship between the cost increase and the capacity on the pipeline. That was purely -- we had a timing impact of some maintenance and expense projects that occurred in the second quarter. As we think about the Bakken capacity, we still have some headroom. We've said it will run on nameplate. Clearly, we're having conversations with a variety of our customers, both -- not just in the Bakken, but also the Powder and the DJ about additional capacity. So we're working through what that expansion might look like and the timing of such.

We'll now take our next question from Danilo Juvane with BMO Capital Markets.

Within the G&P segment, NGL sales volumes averaged 186,000 barrels per day. I recall on the last quarter's call, we talked about the delta year-over-year being driven by ethane recoveries. And since we're talking about ethane recoveries being essentially flat between the first and second quarters, I wanted to make sure that, that increase is just driven by propane plus?

Yes. That volume was entirely driven by propane plus.

Got you. And second question for me, I didn't see anything in the release so I apologize if I missed it. Typically, you'd disclose your equity NGL data and customarily also report hedges that you often update. Did you firstly update the hedges? And is there any equity NGL data available?

That will be part of our Q that we'll file here today. So yes, we didn't put it in the earnings release, but it will be in the 10-Q.

We'll now go to Michael Blum with Wells Fargo.

Wondering could you give us an update on where things stand on the West Texas LPG line and the case there?

This is Kevin. Yes, on West Texas, we're still in the process. From the rate case standpoint, the ALJ has the information and we're awaiting on that, when we continue to expect we'll have resolution on that by the end of the year and are confident in our case.

Okay. And then a little bit of a nitpicky question, but just wonder if you can provide a little background on, there's a footnote in the release related to a contribution to the ONEOK Foundation of 20,000 shares that had a value of $20 million, which looks like it was part of the adjusted EBITDA calculation. Can you just kind of talk about what's going on there?

Michael, this is Walt. The ONEOK Foundation was a foundation that we created in 1997 to support the communities that we operate in. Over the course of the last several years, we haven't made any contributions to that given the business environment. And with the closing of the transaction, we saw it as an opportune time to true up that foundation and made a contribution of $20 million in the form of a preferred stock.

Okay. So on a go forward -- historically, I guess, before the last few years, you would be systematically contributing and that would be running through the statements?

That's correct. And it was periodic. It was not necessarily an annual event. Just from time to time.

Okay.

We'll go to Christine Cho with Barclays.

I actually wanted to start on West Texas. One of your customers there announced plans to build their own NGL pipeline, which would imply that they are pulling volumes off your system once that comes online. Would you be able to give us an idea of how much you're expecting to come off? And how we should think about the outlook for the pipeline and whether or not we should think that the expansion that you guys have previously talked about gets pushed out?

Christine, this is Sheridan. I can't tell you specifically how much any shipper on the pipeline moves. But what I can tell you is no shipper on our system moves more than 25% of the volume on that. So everybody's below 25%. And if we would lose volume there -- we do know of that pipeline coming in -- we are highly confident that we'll be able to recontract that volume at a current -- at definitely better rates than we're getting today because we're getting the lower rates. And also that would give us the opportunity to offer bundled services to also get frac pieces in there. And actually, we are working very diligently and close to having an expansion on the West Texas pipeline backed by customers, and we don't see this new pipeline having any impact at all on the timing of that expansion.

Sheridan, you might clarify, when you said you can't provide that information, you might clarify why that's the case.

Well, the West Texas pipeline is a regulated pipeline. And we can't, as an operator of that pipeline, divulge shipper, specific shipper information. We can only give generalities about what it is, that's why I say nobody is greater than 25%. I can't tell you specifically what that one customer has.

Okay, that's helpful. And then on the Canadian Valley expansion, is that being driven by new acreage dedications or faster-than-expected ramp on production from existing acreage dedications? Also if you could talk about the ability to add more trains at the facilities, if there's a need? And lastly, how should we think about the need or potential for Arbuckle Sterling expansion beyond Sterling III with these additional volumes?

Christine, it is Kevin. Yes, when we look at the STACK in general, obviously, the production growth we've seen, and if you just back up from, away from our specific G&P presence and you look at what the producers are doing in the region, it's been pretty staggering with some of the results they've reported here over the last several months. So most of the vast majority of the capacity need is going to be to serve existing acreage dedications that we have and under long-term contracts. We have added a few small additional contracts here and there. But the primary, the primary expansion and the capacity is needed to serve those existing -- just more growth on those existing contracts.

Yes, we do. As I mentioned earlier, we have the ability to put at least 1 more train and potentially 2 at the Canadian Valley facility as the STACK continues to grow. And again when you're looking at over 100 rigs in the STACK and SCOOP combined, clearly, as we're talking, in Sheridan's business and the NGL side talking to a variety of processors and producers, an expansion of -- additional expansions needed to Arbuckle are not out of the question.

Great. And then just going off the STACK SCOOP, several weeks prior to the announcement of the expansion on Canadian Valley, you guys announced that you'd be offloading 200 million cubic feet a day of processing from that region to a third-party plant. Could you explain why these volumes aren't being directed to the Canadian Valley plant? Is it more of a timing thing, a geographical thing or an economic decision?

It was really all the above. We hadn't -- we just had an attractive opportunity presented and we worked with our counter-party. And the combination of timing, we were able to get this capacity in place sooner than we would have built -- would have been able to build an existing train. And, obviously, economics factored in, we wouldn't have done it if it wasn't attractive to us and our customers.

And Craig Shere with Tuohy Brothers is next.

It looks like on Slide 4 of the deck, that NGL system volumes were up sequentially pretty well. And that was also highlighted in the prepared remarks. But on Slide 7, there's some commentary about sequential operating performance down $9.9 million on lower margin on seasonal product demand. Is this more a product mix issue? Is this something we should see annually? Does it have anything to do with the adjustments to volume through the year on expected third-party interconnects?

No. Craig, this is Kevin. No, it's nothing -- yes, it is seasonal. So from the standpoint of would we expect? And in fact, if you look at last year, it was we were explaining our second quarter, we had similar seasonal impacts. This is volume shift on our North System that are seasonal in nature, and so that is what's driving that aspect. The other -- the cost side is what I referenced earlier, it was just a timing. Typically as we come out of winter, we end up having a higher level of maintenance and expense project activity, and that's what drove that increase sequential quarter-to-quarter from a cost perspective.

But if the overall volumes on your system, the NGL systems were higher sequentially, is it simply a product mix? Or can you explain that a little more?

Yes. The volumes that we're talking about, the volume growth isn't necessarily on the distribution system. Some of the earnings is showing up in the exchange services side of the business. So the volume specifically in the margin on the transportation side is related to that seasonal North System.

Okay. And then a follow-up on Shneur's question about unannounced growth projects. I think you all have already announced with 2 press releases about $300 million in aggregate growth CapEx, an opportunity set that was previously described at $1.5 billion to $2.5 billion. As you think about Arbuckle and West Texas expansion, maybe the Overland Pass JV is needing some expanded capacity over time, additional G&P capacity requirements, do you see this $1.5 billion to $2.5 billion opportunity set reduced by that $300 million? Do you see conditions on the ground expanding, detracting from that initial outlook?

No, Craig, we don't see it reducing. We see it going the other direction, just given the fundamentals that we're seeing under our footprint today.

And in terms of the timing for that, Terry. We didn't have huge dollar amounts relative to your historic spend announce but we did have a couple nice announcements. Could you see more material announcements in the second half here?

We could see that. Certainly in the second half, we could see it in early 2018.

Next is Chris Sighinolfi with Jefferies.

Just want to -- we're at the point in the call where a lot of the big things have been hit, so I wanted to hit on some of the -- maybe some of the, I hate to say it, some of the more minutiae items. But on the optimization and marketing commentary and I know I've inquired with Sheridan about this in the past, but it looked like if I were to follow sort of the OPIS prices or the Bentech reported prices, that regional spreads on prices and intraproduct price perhaps presented an opportunity for greater optimization of marketing year-on-year. You highlighted in the release that it was actually a headwind year-on-year. I know it's a complicated series of decisions around the optimization of marketing activities. And so I didn't know if there was a simplistic way to explain maybe what happened in the market year-on-year net to what we're seeing on the quoted prices?

Chris, really, this is Sheridan. Year-on-year, most or all the delta, the down -- decrease was due to our marketing activity. Really this is due to timing on our inventory that we've sold out in the fourth quarter, third and fourth quarter that we've seen prices drop, in the second quarter that we will realize that back in the fourth quarter, third and fourth quarter when those sales come on. So it was all in marketing, it was not in optimization.

Okay. And that's something, just to clarify what you just said, is that something you saw last year fourth quarter? Or you're saying we would expect to see it in the back half of this year, some of those gains come back to you?

Actually, last year, we had the opposite effect, where we had inventory and prices rose last year, in the second quarter. So we kind of got a little bit of 2 different things going on with our inventory, but the sales are out there in the third and fourth quarter where we'll realize higher third and fourth quarter in the marketing with a decrease in the second quarter.

Got it. Okay, perfect. And then, I guess, following up on the change in the gathered volumes for NGL gathered volumes versus a static forecast on what you were expecting or what you are still expecting on the frac side. Just looking at that, if I think about $25 million of segment EBITDA decline on 25,000 barrels a day of full year movement on the gathering side sort of implies somewhere around $0.065 a gallon. I know when you quote the regional areas, some include frac, some don't. And it would seem like that's more aligned with an area that includes fractionation services, that $0.065.

So I'm just wondering, was that gathering amount planned to be fracked? And you were just sort of previously at the high end of where you thought the frac guidance would be and we're back down in the middle? Or how do we interpret, I guess, the financial implications of the volume? If you could help us with that, it would be helpful.

Well, the volume's kind of spread out over the whole system. But I would say, most of that we were planning on fracking.

Okay. Okay, perfect. I guess, one follow-up question Michael Blum asked earlier, with regard to the preferred equity placement to the charitable contribution. Is there an associated -- it looks like there's an associated preferred distribution on that, at least recorded, small, very small in the quarter. Just wonder if you could give us a sense of what the run rate on that might be?

Sure. It's a 5.5% preferred on the $20 million. So it's reasonably immaterial in the overall scheme of things.

Okay. So just ratably, won't -- that comes out every quarter, there's not an oddity, it's not twice a year, it's every quarter?

It's quarterly, yes.

Final question for me, we've seen a very nice uptick, continued uptick in the average fee on your G&P activities. I'm guessing, based on your earlier commentary that, that might, I think in the fourth quarter you were talking about that maybe sliding back down a little bit given the composition of the volumes. I'm assuming since it's continued to rise, it's the surprise, upside surprise on Williston Basin activities. I'm just wondering how you think about that progressing now given what the activity has been? I think you said $0.85 for the full year. I guess, any help in how you're thinking about producer activity across the 3 regions as we move into 2018 would be really helpful.

Chris, this is Kevin. We clearly see growth in both our regions, in the Williston and the Mid-Continent or the STACK and the SCOOP primarily as we move forward. So yes, the fee rate will move around just literally quarter-to-quarter as that volume mix changes between a little bit higher fee rates in the Williston versus the Mid-Continent. So as the volume growth kind of shifts from one to the other, that fee rate will move around. We still feel good about $0.85-ish through the rest of this year or for the full year. How that moves around will just depend literally on the timing of individual well completions and how the volumes grow sequential quarter-to-quarter.

So Kevin, it's fair to say that we've probably not going to see any step function changes in that weighted average fee rate?

No. Part of the reason for the pretty significant step up from Q1 to Q2 was because we had the severe weather impact to the Williston volumes in Q1. So that as those volumes grew substantially relative -- comparatively, that's what drove up the fee rate. But going forward, no, we shouldn't see step change functions in that fee rate.

Okay. So, the zip code we're in right now is a pretty comfortable zip code, but it might bound around from sort of high to low based on composition quarter-to-quarter, is that a fair understanding?

Yes.

We'll go to Ethan Bellamy with Baird.

You've done -- you guys have done a really great job in the past few years of a multi-year strategic shift in financial structure. And with the merger done, you now have a really good cost of capital. What's next? What's the next corporate strategy goal? Is it more aggressive on M&A? Where do you go from here?

Ethan, as far as aggressiveness on M&A, nothing's really changed in terms of our view. From an M&A perspective, we're always interested in strategic opportunities. Certainly, the challenge associated with those is actionability as you're well aware. Our strategy remains heavily organically focused, it's certainly where we -- building off this big asset footprint that we have. The incremental returns, or the incremental investments that we're making and the returns that we're seeing are very attractive.

And we'll stay focused on taking care of our customer needs, building off of this existing footprint. And then from time to time, acquisition opportunities, if they present themselves and they fit with this NGL-centric kind of strategy that we have, certainly, we'll pursue those. But that's kind of how to think about it.

So the seachange in your cost of capital really hasn't changed your strategy or the way you're thinking about running things going forward?

It really hasn't. I mean, we're certainly from a business perspective. And as we think about our growth strategies, they're still spot on with where we've been in the past. I will tell you that we've always been in a prospecting mode in terms of M&A regardless of our structure. And we're still there, but they got to certainly make sense, got to make a lot of sense for us.

Okay. And then one really granular question. How much behind pipe gas in the Bakken is still low-hanging fruit in terms of capturing things that are being flared right now?

When you say behind pipe, are you talking about it from a geologic perspective?

Yes, I am.

That's -- so Three Forks.

I heard a couple questions, are you just wanting to get at how much low-hanging fruit from a flaring perspective?

Yes. Well, I'm just thinking about maybe also something that's getting flared now, but you know that there's going to be some wells drilled, you don't have pipe in the area now, that kind of -- I'm just trying to get a sense for the opportunity there, because I know a lot of your volume catch-up has been in terms of going out and capturing that flared gas.

Yes. No, in large part, we have captured a good chunk of that low-hanging fruit. I mean, we still estimate we may have 60 million to 70 million cubic feet a day flaring behind our system. But again, as our volumes have grown, we've lowered -- at the same time, we've lowered that flared gas. So there's always going to be some level of flaring. We might estimate 30 million to 40 million cubic feet a day that's just going to be ongoing. So there may another 20 million that we're continuing to pursue, that you'd kind of call low-hanging fruit. But for the most part, our operations team has done a fantastic job. And relative to the rest of the basin, our flaring is well below the state-wide averages.

And is the state less in your face about this now?

Well, yes, from the standpoint of the industry in total has delivered and specifically us. So yes, from the standpoint that industry stepped up and has met the flaring targets and takes it extremely seriously and as we worked with our customers to drive the flaring down, yes, it is -- limited and eased the pressure.

And that will conclude our question-and-answer session. I'd like to turn it back to Andrew Ziola for any additional or closing remarks.

Okay. Well, thank you all very much for joining us. Our quiet period for the third quarter starts when we close our books in early October and extends until earnings are released after the market closes in early November.

Again thank you for joining us and feel free to follow up with me in the coming days. Have a good rest of your day.

Thank you very much. And that does conclude our conference for today. I'd like to thank everyone for your participation.