歐尼克 (OKE) 2015 Q4 法說會逐字稿

Good day and welcome to the fourth-quarter 2015 ONEOK and ONEOK Partners earnings conference call. Today's call is being recorded.

At this time I would like to turn the conference over to Mr. T.D. Eureste. Please go ahead, sir.

Thank you. And welcome to ONEOK and ONEOK Partners' fourth-quarter and year-end 2015 earnings conference call. A reminder that statements made during this call that might include ONEOK or ONEOK Partners' expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provisions of the Securities Act 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 is Terry Spencer, President and CEO of ONEOK and ONEOK Partners.

Thank you, T.D. Good morning and thanks for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners.

On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, our Chief Financial Officer; Wes Christensen, Senior Vice President, Operations; Sheridan Swords, Senior Vice President, Natural Gas Liquids; Kevin Burdick, Senior Vice President, Natural Gas Gathering and Processing; and Phil May, Senior Vice President, Natural Gas Pipelines.

Additional key financial and operational information has been updated in a short presentation and is posted on ONEOK's and ONEOK Partners' websites. Let's start by discussing ONEOK and ONEOK Partners' accomplishments in 2015. Then I will hand it off to Derek for a financial update and finish by reviewing our 2016 financial guidance, which we maintained for both ONEOK and ONEOK Partners in last night's release.

Our uniquely positioned assets delivered higher ONEOK Partners fourth-quarter and 2015 adjusted EBITDA in a very challenging market and we delivered on our expectation to significantly grow natural gas and natural gas liquids volumes and earnings in the second half of the year. The partnership grew its adjusted EBITDA throughout the year by nearly 40% from the first quarter to the fourth quarter 2015, ending the year with $450 million in fourth-quarter adjusted EBITDA. The partnership also improved its quarterly distribution coverage to 1.03 times.

These results were driven by a significant ramp in natural gas volumes gathered and processed across our system, especially in the Williston Basin, as we connected more than 820 additional wells, captured more flared volumes from existing wells, completed six field compression projects and our Lonesome Creek natural gas processing plant, and restructured several contracts earlier than expected. And in the Mid-Continent volumes increased late in the year as a large producer customer completed wells that had been drilled earlier in the year.

The Natural Gas Liquids segment, which is connected to more than 180 natural gas processing plants, continued to benefit from natural gas liquids processed volume growth in the Williston Basin. Seven new third-party natural gas processing plants were connected in 2015. We also realized solid volume performance on our West Texas LPG pipeline system from our long-haul customers, as we continue to provide quality service at a good value.

With nearly 100% of its earnings fee-based, the Natural Gas Pipeline segment had another solid year. This segment is taking advantage of incremental demands due to lower natural gas prices through its uniquely-positioned assets with the announcement of the Roadrunner Gas Transmission Pipeline and WesTex Pipeline expansion serving growing markets in Mexico.

In 2015, we made significant progress toward reducing commodity risk in our business, which is expected to reduce earnings volatility over the long term. As a result, we expect 2016 fee-based earnings to be approximately 85%, a significant improvement from 66% in 2014. Drivers of this increase include growing the fee-based exchange services volumes in the Natural Gas Liquids segment and contract restructuring in the Gathering and Processing segment.

The efforts of contract restructuring in the Gathering and Processing segment can be seen by the increase in our average fee rate. The average fee rate for the fourth quarter 2015 was $0.55, a nearly 60% increase compared with $0.35 in the first quarter 2015.

At ONEOK we remain committed to being a supportive general partner, as evidenced by the $650 million equity investment in the partnership in mid-2015, which we expect to result in increased distributions from ONEOK's higher ownership percentage in ONEOK Partners. Our extensive integrated network of natural gas and natural gas liquids assets delivered solid results in 2015 and has positioned us well for 2016.

That concludes my opening remarks. Derek?

Thanks, Terry. I'll start by highlighting the financial steps we took in 2015 and early 2016 that positioned us well for 2016 and into 2017.

With a high priority on maintaining the partnership's investment-grade credit ratings, we took decisive steps to manage its balance sheet by high-grading its growth projects and reducing capital spending by nearly $1.6 billion in 2015 from our original 2015 capital guidance. We issued $750 million of equity in August, along with nearly $280 million of additional equity through the at-the-market program during 2015; termed out $800 million of short-term debt in March; and most recently, entered into a $1 billion three-year unsecured term loan, which effectively refinances the 2016 long-term debt maturities at a low cost.

With the financial steps we have taken and the momentum and volume growth in earnings leading into 2016, we expect to achieve our 2016 financial guidance.

At ONEOK Partners, we expect not to need public debt or equity issuances well to 2017, which includes no equity from the at-the-market equity program; to keep distributions flat for the year; deliver distribution coverage of 1 times or better for 2016; and obtain GAAP debt-to-EBITDA ratio of 4.2 times or less by late 2016. At ONEOK, we expect to keep dividends flat for the year; pay no cash income taxes in 2016; and generate approximately $160 million of free cash flow after dividends in 2016, which along with $90 million of cash at the end of 2015, provides ONEOK with significant flexibility to support ONEOK Partners if needed.

For growth capital in 2016, we expect to spend $320 million in the Gathering and Processing segment and $70 million each in the Natural Gas Liquids and Natural Gas Pipeline segments for a total of $460 million as previously guided. As producer needs evolve throughout the balance of the year and into 2017, we have the flexibility to significantly reduce growth capital, particularly in the gathering and processing segment, as we optimize our systems and available capacity.

Additionally, we have been able to realize reduced operating costs and capital costs from our service providers across our operations. We continue to control operating costs and have reduced contract labor. We expect this trend to continue into 2016.

As (technical difficulty) of 2015, a number of our large maintenance projects came in significantly under budget, especially the projects scheduled towards the second half of 2015, as service providers reduced costs and bid very aggressively due to market conditions.

On the topic of counterparty credit risk, we consider our credit exposure to be low across all three of our operating segments. The partnership had no single customer representing more than 10% of revenues and only 15 customers individually represented 1% or more of revenues. Additionally, of the top 10 customers, which represented 38% of revenue, nine are investment grade or provide full credit support. Many of our top 10 customers are natural gas liquids segment customers comprised of large petrochemical and integrated oil companies.

Taking a look at our credit profile within our three segments, where we consider investment grade as rated by the ratings agencies or comparable internal ratings or secured by letters of credit or other collateral. The Natural Gas Pipeline segment received more than 85% of its 2015 revenue from investment-grade customers, who are primarily large electric and natural gas utilities.

The Natural Gas Liquids segment has limited credit exposure in its exchange service fee earnings as most contracts -- in most contracts the natural gas liquids are purchased and proceeds are remitted from the partnership to the liquids producer, less a fee. And more than 80% of 2015 commodity sales were to investment-grade customers.

And, finally, the Gathering and Processing segment's credit risk is limited as in most contracts the partnership remits the proceeds under the percent of proceeds contracts to the producer, net of ONEOK Partners' share of those proceeds as well as the fees charged. 99% of the segment's 2015 downstream sales were to investment-grade customers.

2015 results at both ONEOK at ONEOK Partners include the impact from non-cash impairment charges totaling $264 million, primarily related to investments in the coal bed methane area of the Powder River Basin. The partnership remains highly committed to maintaining our investment-grade credit ratings, having a solid balance sheet and ample liquidity to support our capital program, ending 2015 with $1.8 billion available on its credit facility. The partnership's GAAP debt to adjusted EBITDA on a run-rate basis is 4.1 times, reflecting earnings growth during the year.

Distribution coverage remains an important metric for us as well. We expect distribution coverage of 1 times or better for 2016 by growing our cash flows through volume growth, cost savings, and efficiency improvements.

ONEOK, on a standalone basis, ended 2015 with over $90 million of cash in an undrawn $300 million credit facility. The partnership is advantage by having a strong, supportive general partner in ONEOK. With the significant excess dividend coverage, ONEOK has the resources that may be used to further support the partnership, if needed, as it navigates these uncertain times.

Terry, that concludes my remarks.

Thank you, Derek. Let's walk through our 2016 financial guidance and key assumptions by segment, starting with our largest segment.

The Natural Gas Liquids segment is expected to contribute $995 million in operating income and equity earnings in 2016. Additionally, we expect the Natural Gas Liquids volumes and earnings to be weighted towards the mid to second half of 2016. Approximately 90% of the expected earnings in this segment are fee-based from the exchange services and transportation businesses.

We continue to expect the partnership's natural gas liquids volumes gathered to increase in 2016 primarily from Williston Basin natural gas liquids volume growth expected from our gathering and processing assets in the basin, including the expected connection of the Bear Creek plant, and one third-party natural gas processing plant in 2016. Approximately 60% of the segment's natural gas liquids volumes gathered come from the Mid-Continent, with the majority of the gathering volume coming from third-party processing plants. Our unique natural gas liquids position in the Mid-Continent is similar to the position we have in the Williston with the partnership's gathering and processing assets, as we are connected to most of the third-party plants in the region.

We expect to continue to benefit from natural gas liquids volumes gathered through our West Texas LPG system, where nearly 26% of the segment's volume originates. The segment is connected to more than 60 natural gas processing plants in the Permian Basin and is expected to connect one additional plant in 2016. And we expect to receive the full benefit in 2016 of increased tariffs.

Finally, we moved the completion of the Bakken NGL pipeline expansion to the third quarter 2018 due to a slower expected rate of volume growth. The realigned timing of the expansion has no impact on financial or capital guidance for 2016.

Driving the earnings growth in the Natural Gas Gathering and Processing segment in 2016 is natural gas volume growth in the Williston Basin and enhanced margins due to the contract restructuring efforts. In the Williston, we expect to average 740 million cubic feet per day of natural gas gathered volume in 2016. Our gathered volumes early in the year have been very strong as we reached nearly 800 million cubic feet per day in February.

The recently completed Lonesome Creek plant and compression projects have already added nearly $100 million a day of incremental volume to our system, most of which has come from capturing previously flared gas.

We continue to have approximately 24 rigs operating and more than 500 drilled uncompleted wells on our dedicated acreage. Given this activity, we expect 215 to 350 new well connections to our system in 2016. To put the expected 2016 volume outlook into context, if every rig were to have stopped drilling on January 1, 2016, and we did not connect any new wells in 2016, we would expect an average gathered volume of 720 million cubic feet per day in 2016, slightly below our guidance for the Williston.

Natural gas volume growth in 2016 will not reflect a pronounced second-half ramp up as we experienced in 2015. We do expect volumes to slightly decline through the summer until our 80 million cubic feet per day Bear Creek plant comes online, and we expect to capture an incremental 40 million cubic feet per day of gas currently flaring in Dunn County.

In the Mid-Continent we continue to be in constant communication with our producer customers regarding their drilling and completion activity. And similar to the Williston, the Mid-Continent volume exited 2015 at a high rate.

As I mentioned earlier, the segment did receive an early benefit from our contract restructuring efforts in the fourth quarter 2015. However, 2016 is expected to receive the full benefit of these efforts and we expect another increase in the average fee rate in the first quarter 2016 from the $0.55 the segment averaged in the fourth quarter 2015.

In the Natural Gas Pipeline segment, 2016 earnings are expected to remain more than 95% fee-based, with more than 90% of the segment's transportation capacity and more than 75% of its natural gas storage capacity contracted for the year. The first phase of the Roadrunner Gas Transmission Pipeline is on schedule to be complete next month and is fully subscribed under 25-year firm demand charge fee-based commitments, with the second phase expect the complete in the first quarter 2017.

Before closing, I would like to discuss future demand growth for ethane, which we expect to be a significant opportunity for the natural gas liquids segment, we move through 2017 and 2018. Approximately 400,000 barrels per day of incremental ethane demand from new world scale petrochemical crackers is expected to come online by the third quarter of 2017 and nearly 164,000 barrels per day more by first quarter 2019. We expect this new demand, combined with additional ethane exporting infrastructure, to significantly reduce the ethane excess supply overhang and put upward pressure on ethane prices and bringing most natural gas processing plants into full ethane recovery sometime in mid-2018.

Nearly one-third of US ethane, or approximately 180,000 barrels per day, is dedicated and connected to our natural gas liquids system, but is currently not producing due to insufficient ethane demand. We are well-positioned to transport and fractionate substantial incremental ethane volumes once the natural gas processing plants we are connected to transition into full ethane recovery in response to growing US petrochemical demand. We expect little to no additional capital expenditures needed to bring this ethane on to our system, as we already constructed the natural gas liquids infrastructure necessary to connect supply to the Gulf Coast region.

The total incremental adjusted EBITDA benefit to the partnership, if all of the natural gas processing plants we are connected to enter full ethane recovery, could be in the range of $200 million per year. With the Natural Gas Liquids segment's unique and extensive asset position, we can deliver significant ethane supplies to the Gulf Coast markets from Williston, Mid-Continent, and Permian Basins.

Since we issued guidance in December, the commodity price environment has continued to be unstable and many of our producer customers have reduced their capital expenditure plans for 2016. While these challenges remain, we will continue to remain focused on serving our customers, reducing risk, controlling costs, managing our balance sheet prudently, and reducing capital needs. As we've discussed on this call, more than 85% of the partnership's operating income and equity earnings comes from primarily fee-based activities, underpinned by its large 37,000-mile integrated natural gas and natural gas liquids network with opportunities to grow as cash flows even in a lower capital spending environment.

In 2016, we expect to finish the year within our financial guidance, driven by our uniquely-positioned assets. We are less than 60 days into 2016 and we expect, similar to 2015, opportunities and challenges throughout the year. We will be proactive in our approach to these opportunities and challenges and prudent in our decision-making, all while keeping in mind the long-term interest of our investors.

I would like to thank our employees across the country for their strong performance, hard work, and dedication in 2015. Many of our employees have experienced these difficult industry cycles before and they know what to do: manage costs, be efficient, be creative, and operate safely and reliably, all while being focused on providing quality service to our customers. And many thanks to all of our stakeholders for your continued support of ONEOK and ONEOK Partners.

Operator, we are now ready for questions.

(Operator Instructions) Eric Genco, Citi.

Good morning. My first question is actually a little bit of a two-parter. I just want to dig a little more on the potential on the ethane recovery.

It obviously seems like this is a pretty major opportunity and no incremental capital. Not really if, but maybe when but -- and I know it's early; I just would like to get a better sense for the timing and maybe the mechanics and how some of this might play out in terms of the split between where you will feel the impact in the Permian, Mid-Continent, and the Bakken.

I guess also, in light of the comment that you alluded to in your remarks that perhaps the Permian is going to see a meaningful uplift even in 2016 in terms of the rate, bringing that more to market rates. I'd just like to get a better sense for that if you can.

Sure, Eric. I'll just make a couple of comments and then let Sheridan kind of follow this thing up. In the slide deck that we provided there is actually a slide in there that gives you -- shows you the sources of where that incremental ethane originates.

And if you think about it in terms of which ethane is going to come on, obviously those with the lowest transportation cost burden will come on sooner. So you have to think about it in terms of the Gulf Coast probably coming on sooner, the Mid-Continent and West Texas probably next, and then you got to think about the Marcellus and the Rockies. It's kind of in that order and we provided that table to give you what that -- as an industry, what that volume impact is.

So Sheridan, do you want to provide a little more color and then talk about West Texas?

Only thing I would say is that I think we will start seeing; as we enter into 2017 is when we will start seeing meaningful ethane starting to come out. And as Terry said, West Texas of our system will be first, but that is where we have the least amount of ethane rejection on our system, followed by the Mid-Continent, where we have the most volume off currently, and then last will be -- which will be 2018 or beyond, which will be the Bakken.

In terms of West Texas pipeline and the rate increase, in July of 2015 be brought the tariff rates, the uncommitted tariff rates on the West Texas pipeline closer to market. So we only realized half the year of that rate increase, which in 2016 we will realize the complete year of that rate increase.

Okay. But that's not necessarily getting you to the sort of 5 to 7 times as the long-term target, it's more just the benefit of half the year at this point?

Yes. It's benefit of having the full year. We don't anticipate raise in rates. We don't have in our guidance raising rates further in West Texas in 2016.

Okay, that's very helpful. I guess in switching gears a little bit maybe, I'd just like to get some of your thoughts on your most recent conversation with the rating agencies and how that's going.

You have alluded to all the accomplishments and the things that were on their checklist in 2015: the equity offering in August, renegotiating POP, addressing refinancing for 2016. But in light of, I guess, some of the more recent actions in the E&P space I'm curious if there's been any shift in the tone or the targets that they set for you.

I'm also curious to what extent they have looked at potential uplift for ethane. I know it's typical in some leverage ratios to make an adjustment for capital that is already in the ground and earnings that's likely to come on. Is that something that they are considering and looking at at this point, or is it too early to tell?

Eric, this is Derek. We do communicate regularly with the credit-rating agencies and certainly we intend to continue to do so. I think we've got along track record of taking those prudent actions, and you checked them off the list pretty nicely, just as I would.

The term loan and sort of being ahead of our financing needs I think is helpful and those things driving commodity risk out, reducing capital. I think all of those sort of credit-friendly actions that we've taken over time plays into their thought process.

I can't tell you to what extent they may or may not be including ethane uplift. I suspect not much, but historically they have understood and added back some credit I think for the capital spending over time. So what I think they look for is a track record of plan to continue to reduce leverage.

And as I mentioned my remarks, the GAAP debt to EBITDA of 4.1 times on a run rate basis is certainly supporting that we are headed in the right direction. And I think the unique aspects of our footprint, the tailwinds in terms of volume that Terry mentioned in the Williston, capturing the flared gas -- those sorts of things I think all play into their thought process.

Derek, the only thing I would add to that is that I think the rating agencies, from a macro perspective, are aware of the growth that is happening in that petrochemical space. Now, whether they actually take that into consideration in any of their analysis, as Derek indicated, we don't know.

But I think they are certainly aware of it and I think that -- I think if you were to ask them about it I think that they do view it as a strong positive. But whether they've actually factored that into any analysis, again we don't know.

Okay, understood. Thank you very much and good luck, congratulations.

Christine Cho, Barclays.

Congrats on the quarter. In the presentation, you guys show that the natural gas GNP volumes are 662 million cubic feet a day in the Rockies for the quarter. Would you be able to split that between Powder River and Williston?

Christine, I let Kevin handle that.

Christine, you can assume there's roughly 30 million a day of Powder gas in that number.

Okay. And then I just wanted to touch on the ethane opportunity that you guys talked about. As you guys say, on the slide you guys point to that 150,000 to 180,000 barrels per day being rejected across your system. Could you split that up a little better from Williston, Mid-Continent, and Permian? I know you said the least amount is coming out of the Permian, but any sort of percentages or ballparks would be helpful.

Christine, this is Sheridan. You have over 100,000 barrels a day of ethane off in the Mid-Continent, more like 120,000, 135,000; 36,000 in the Bakken, and virtually 10,000 or less in the Permian.

Okay, great. Thank you. Then as a follow-up to that question, you guys have a whole bunch of NGL distribution pipes leading to the Gulf Coast from Conway and Mid-Continent. What is the utilization currently on all the pipes between those two points and are you guys collecting minimum volume payments for any of the volumes?

Asked another way, are customers currently paying for volumes they aren't shipping?

The capacity we have between Conway and Mont Belvieu is about 60% utilized between the Sterling pipelines and the Arbuckle pipelines. And we think about our minimum volume commitments that is usually for a bundled service, so yes, there are some minimum volumes that have Belvieu redelivery that we are collecting today.

Okay, I'll follow up offline. But, lastly, is there sufficient ethane fractionation capacity in storage along the Gulf Coast to accommodate all this ethane that's going to have to come out?

On our system we have enough ethane through our fraction -- we have enough capacity through our fractionators to fractionate all of the ethane on our system. And we do have the storage capacity and the connectivity into the petchems to be able to deliver that to market.

Okay. But that's specifically for your system; I was kind of more asking like does the industry have enough.

Christine, you'd have to ask all the other individual fractionators down there, but my sense is, yes, there is plenty of capacity to frac this ethane. Most of the fractionators, when they are constructed, they are constructed for a full ethane slate and so when this ethane is being rejected, it just takes it out of the first tower of the fractionator.

Okay, perfect. That's what I thought. Great, thank you.

Becca Followill, US Capital Advisors.

Good morning. I think you guys talked about that your guidance included about 300 to 350 well connects in the Williston Basin during 2016. Is that correct?

That's 250 to 350.

250 to 350. What I'm looking at a page 8 of the presentation on your guidance of 740 million a day, it looks like that includes 100 well connects.

I'm going to make just a general comment about that slide, Becca, and then I will let Kevin jump into more of the details. That's a theoretical depiction assuming that all of the flared gas gets connected and that we experience a 20% decline; based upon that you would need 100 wells. But now I will let Kevin take it the rest of the way.

Becca, a couple of things and dynamics that are going on in that -- transitioning from that slide to our guidance. Like Terry mentioned, that's kind of a theoretical, assuming all the flares were out we'll -- in our guidance volumes we factor in some level, minimal level of flaring. Keep in mind we've got Dunn County, where gas is going to flare until we get the Bear Creek plant built in the third quarter. We also factor in a little bit for weather during the winter months, and then just some general operational cushion, or whatever you want to call it, just to pull volumes back a little bit.

So that's the incremental difference between the 100 well connects that's referenced in the stairstep slide and our guidance. But we do feel strong; when you look at the activity that's currently there in the basin and the number of rigs on our acreage and then you look at the drilled and uncompleted backlog, we feel that the 250 to 350 is a really good number to achieve.

That's even despite recent announcements by some of the producers about suspending completion and pairing back budgets, correct?

Yes.

Okay, great. Thank you very much.

Craig Shere, Tuohy Brothers.

Good morning. Congratulations on another good quarter. So expanding on Eric and Christine's ethane recovery question, how should we be thinking about margins regionally as ethane recovery rolls in? It's not going to be -- you're not going to get over $0.30 out of the Bakken, are you?

No, Craig; this is Sheridan. We will not receive $0.30. Typically across our whole system ethane is discounted to the C3-plus, so we will realize a lower margin than the $0.30 out of the Bakken.

Okay. Roughly speaking, against what you're getting on the C3-plus, should we be thinking like $0.05-plus spreads or what should be thinking? Is it even across -- those spreads across the system?

No, it will not be even across the system. Some volume will come on that will have Conway options, some volume will have Belvieu options; and they have all different kind of spreads depending on where they are. Obviously, if you are in the Bakken, they are going to have the highest margins and the Mid-Continent will be lower, and obviously a little bit in the Permian will be the lowest.

Craig, just let me step in here. You used the word spreads; I think what's -- they are fees. It's not a spread play; it's a fee and so there will be different rates, as Sheridan indicates, for different areas. And it's very common for us to have a lower fee rate for the ethane component than the C3-plus barrel.

Understood. I kind of meant the discount to what you are charging for the C3-plus. That's the spread I was referring to.

I hear you, okay. I understand now. I just trying to be -- make sure. I don't want any misunderstanding.

Fair enough. Thinking about 2017 capital needs, I understand you don't have any need to raise debt or equity until well into 2017, but your growth CapEx in 2017 for the already approved projects and execution should fall off really materially year over year. So when you think about incremental capital needs in 2017, is that just terming things out, rightsizing the balance sheet a little bit? There's not a lot of spend that you have planned, right?

I think that's a fair assessment, Craig. We don't have anything of major strategic significance, in particular in the G&P segment, for 2017. So yes, you are thinking about it in the right way.

In particular, if we get in this lower-for-longer mode, we do have the ability to flex down this -- our current rate of capital spend down considerably. Now we have not guided to that and don't intend to guide to that in this call, but I think you're thinking about it the right way.

Is there some range or percentage that you think you can shave off in a worst-case scenario?

Well, let me give you this: it is significant and you could get to a point where just your routine growth -- well connects, small infrastructure projects, compressor type projects -- could be --. The core of your organic growth opportunities is that kind of stuff and so it would be a significant reduction in the capital spend that we are experiencing here in 2016, a significant reduction in 2017 if this environment -- if the lower-for-longer environment persists.

Fair enough. Last question, following up on Becca's query about the 100 well connects on that theoretical slide versus the 250 guidance. Can you -- I know we are in a period flux and who knows with going to happen next quarter, but implicit in that questioning is that you continue to have a cushion supporting your operations in a worst-case scenario, even in 2017? Because you're not using it all this year in terms of flared gas and the drilled, but uncompleted, well inventories.

Do you want to address any of that in terms of how measurably things may or may not fall off next year in a worst-case scenario?

Well, let me make a comment and then Kevin can clean it up. Okay, so flared gas, let me just tell you, it's not an exact science. It's quite possible we could have more flared gas than we actually believe we have, because every time we turn on a compressor station it seems like the wells behind that particular compressor station outperform our expectations. Time and time again, more gas is showing up than what we thought.

And so that's what we're dealing with here. That is what we dealt with in the fourth quarter of last year and that is what we're dealing with as we plow through first quarter of 2016. I think we would expect that it's probably not going to turn out exactly the way we think and it could be very possible that we are a bit conservative on our assessments and thoughts about flared gas.

Kevin, you got anything to add to that?

No, the only thing I would add, Terry, is that -- again back to the drilled-but-uncompleted backlog. When you think about that we've got 550 or a little more than that behind our acreage, I don't think there's any expectation that all of that is going to get worked off this year. So as you move into through this year and you move into 2017, even if the flared gas volumes go very low, you've still got some support from that drilled-but-uncompleted backlog that producers can bring on relatively quickly as prices improve.

Very helpful, thank you.

Jeremy Tonet, JPMorgan.

Morning. Just wanted to touch back on the call as far as the $0.55 fee that you guys saw. How do you expect that to trend during 2016 again?

Jeremy, we're not going to guide in the first quarter as to what that fee rate is going to be, but we are expecting it to increase. And if there's any other color, I'll let Kevin address it.

Jeremy, just that we did experience an increase in the fourth quarter that was a little ahead of our expectations by getting some of the restructurings done earlier than anticipated. So while we do expect it to increase, I don't think it will be as pronounced as the increase from Q3 to Q4.

Okay, great. Thanks for that. One of the questions we commonly get in this space is thinking about maintenance CapEx. How do you guys think about it as far as the depletion to the wells?

How do you think about well connects as far as maintenance CapEx? Did that impact kind of -- the maintenance CapEx revisions over the course of the year? Any color you could provide there would be great.

Yes, Jeremy, how we look at it -- and Derek can jump in here if I mess this up. When we think about growth capital, well connects and those types of things, the volume through our systems, we consider that growth capital. If it's attached to revenues, if it's a revenue-generating activity, we call it growth.

If it's related to the straight-up maintenance of the pipeline system, mechanical integrity of the assets, we call that maintenance capital. That's a distinction we have used for a long time and I think many of our peers use that same thought process. Does that help you?

Sure, yes. Maybe just in general, as far as maintenance CapEx coming in lower across the year, if you could just help us think through that a bit more as far as like savings through reductions in contractors or --. Any color there would be great.

I'm going to let Wes Christensen take that.

Sure. In 2015, we did benefit from lower contractor costs across our projects, as well as using less contractors. Also, our materials and supplies that we consume inside of those projects we've seen some benefit in lower costs there as well.

Then the last item, maybe just the timing of the projects. We expect to see these types of trends continue through 2016.

Great, that's very helpful. Then just one last housekeeping item. I think there was an asset sale gain of about $6 million in the quarter. Could you provide some color on that, please?

Sure, Jeremy; this is Derek. We routinely will sell off small pieces of pipe or things like that that really aren't integral to our system, so that's all that is. I think it's fairly consistent from year to year actually. We've got kind of a small amount every year. It really only impacts DCF by less than $1 million.

Oh, so the $6 million, was that a non-cash item that is backed out in DCF then?

Exactly.

Okay, great. Thanks.

Kristina Kazarian, Deutsche Bank.

Just wanted to make sure I was understanding something that was asked earlier about leverage. Can you just -- and rating agencies.

Can you just help me understand how the conversations have been going? Because I think OKS is still on negative at both. I mean you guys have listed a bunch of positives you guys have executed on since then, so what should I be watching for or thinking about? Or have they communicated what you guys need to execute in order to have OKS removed from negative outlook at either?

Kristina, this is Derek. Of course they have wanted to see us execute on those things I mentioned before. Broadly, the macro environment I think is difficult for them to take us off of any sort of a watch at this point. We really forced their hand last year in August when we did the ONEOK bond deal where they had to rate that debt. That's when they put us on negative outlook.

My personal opinion is it's difficult for them to remove that given the broader macro environment, the low pricing, and so forth.

Kristina, the only thing I would add to that is I think they've been appreciative of the fact that we have decisively cut capital spending; have made some really prudent decisions and that we have voiced to them our willingness to continue to cut capital if the environment dictates.

That's great, which leads into my second follow-up one. And I know you mentioned this earlier about the flex down on possible spend. And I'm not looking for a number at all there, but if I think about it being a lower-for-longer environment, can you touch on maybe some other things you might think about, too?

Are there small non-core asset sales? How do I think about maybe -- I know there was a number in the press release, but financial support OKE could provide for OKS and just things in that vein?

Well, Kristina, we obviously evaluate our assets at all times, but we don't see asset sales as a primary driver for us going forward. The financial flexibility that we have from ONEOK generating excess cash gives us plenty of different tools that we can use, whether it be equity purchases or considering thoughts around the IDR. We constantly evaluate what would be best for ONEOK and ONEOK Partners and we're happy to have those tools at our disposal as we move forward.

Then last one for me. I know we saw the fee increase in the 4Q was ahead of expectations. Just an update on progress and in terms of how many contract left could I see renegotiations on or anything color there.

Kristina, most of our objectives have been met in the Williston Basin, but generally speaking we continue to, where we can, renegotiate contracts to reduce commodity price exposure and, where we can, increase margins. That's just an ongoing process. There might be a few more in the Williston, but as I say, for the most part we are done there. Western Oklahoma and Kansas, of course, will be areas of continual focus.

Perfect. Thanks, guys. Appreciate the time today.

Elvira Scotto, RBC Capital Markets.

Good morning. Thanks for all the color that you provided on your volume expectations in the Williston Basin, but do you think maybe you can provide a little more color behind your Mid-Continent volume guidance, especially given how the commodity price environment has changed and producer commentary? And can you provide any, I don't know, maybe some sensitivity around that guidance?

First of all, Elvira, my contribution is going to be that rig counts in the Mid-Continent have been pretty resilient, even in this latest leg down, compared to some of the other basins. So I think that has been somewhat surprising to us.

So Kevin, if you want to talk a little bit more specifically on volumes?

The Mid-Continent area, especially the Stack, Cana, Scoop areas, it's kind of interesting because you've got really competing data points. Even as late as last week with some calls that were out there, the performance and the results that many of our customers and other producers in the area are seeing are really outstanding. But yet there's some discussions of some delays.

We're watching that very closely. We're in constant communication with all of our customers in the Mid-Continent. I guess the way I think about it it's really a function of just time.

Those reserves are there; the results are strong. So the volumes will come, it's just, okay, is it going to be fourth quarter this year, third quarter this year, or push into 2017? We will be watching that closely over the next couple of months.

Okay, that's really helpful. And then, in terms of cost-cutting opportunities, do you see any cost-cutting opportunity in 2016 and is that baked into your guidance?

Yes, we do have some continued management of our costs and, obviously, we are still seeing downward pressure on vendor costs. We've got contractor costs that are coming down, particularly as we are in a lower growth mode.

Wes, do anything else you could add to that?

No, I think that is consistent. We will see that in our O&M as well as we've been seeing it in our maintenance capital.

Got you. Okay, thanks a lot.

John Edwards, Credit Suisse.

Good morning. Thanks for taking my question. Terry, I'm just curious on the guidance; you affirmed the guidance, but obviously since you've provided it things have deteriorated significantly. So what improvements I guess are you looking to in your own performance there that would enable you to affirm if you could?

Certainly, John, the outperformance -- the exceedance of expectations in volume performance is really key. We were -- we continue to be very well hedged, as you can see from the information that we provided to you, and we are going to get the full year of the contract restructuring benefit in 2016.

So from a pricing point of view standpoint, we think that there's going to be some correction or some significant improvement in prices as we move throughout the year, based upon our current point of view. As we sit today, we like our guidance. And as Kevin indicated, we're going to continue to assess the producer activity and try and get as much visibility as we can. And if we think updates are necessary, we will come back to you.

Okay, that's helpful. Then just -- you may have covered this; I got disconnected part of the call. But in terms of the -- you were pointing to on the NGL segment sort of a second-half volume story there. If you could just provide a little bit more color or detail on how you see that playing out.

First, we start up in the Bakken as you saw the volumes, even though they are slower growth than we saw last year, they continue to grow, especially with the Bear Creek plant coming online, and also with the -- we are going to connect a third-party processing plant up there as well this year. We have plants in the Mid-Continent that are in the Scoop and the Stack that will be completed later on this year. So that's basically where we see the volume ramp coming from in our volumes is from those two plays.

Okay, great. Then, lastly, just in terms of counterparty risk, to what extent are you baking that into your guidance?

John, I covered that in our remarks and there's a new slide in the presentation that accompanies the news release that gives you a lot of detail on that. We actually feel very good about the counterparty credit risk that have and we are not exposed, overly exposed to any particular customer, so good diversification. So we are not expecting any sort of material credit losses.

Okay, great. Appreciate that clarification. Thanks, that's all I had.

I will turn it back to Mr. T.D. Eureste for any additional or closing comments.

Thank you. Our quiet period for the first quarter starts when we close our books in early April and extends till earnings are released after market closes in early May. Thank you for joining us.

That will conclude today's conference. We would like to thank everyone for their participation.