Good day, everyone, and welcome to the ONEOK and ONEOK Partners Fourth Quarter 2013 Earnings Call. Today's conference is being recorded. At this time, it is my pleasure to turn the conference over to T.D. Eureste. Please go ahead.

Thank you and welcome to ONEOK and ONEOK Partners Fourth Quarter and Year-end 2013 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 provision 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. Starting our earnings conference call is Terry Spencer, President and CEO of ONEOK and ONEOK Partners. Terry?

Thanks, T.D. Good morning, and thanks for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners. Joining me on the conference call today is Derek Reiners, our Chief Financial Officer, who will review our financial results. Also with me, and available to answer your questions, are: Rob Martinovich, our Executive Vice President of Commercial; Sheridan Swords, our Senior Vice President of Natural Gas Liquids and Wes Christensen, our Senior Vice President of Operations. On this morning's call, we will review our fourth quarter and year-end 2013 financial and operating results, bring you up-to-date on our current capital growth projects and review the NGL markets. We'll discuss my areas of focus as CEO and what's important to me, and we'll answer your questions. Let's start with our fourth quarter performance. ONEOK's fourth quarter performance was driven by continued volume growth in ONEOK Partners, with increases in natural gas gathered and processed and natural gas liquids gathered as a result of the capital growth projects we completed, offset by higher operating costs and one-time costs associated with the separation of our natural gas distribution business into ONE Gas. ONEOK Partners fourth quarter 2013 results were up as a result of the volume growth I just mentioned. Derek will now review ONEOK's and ONEOK Partners' financial highlights and then I'll review our operating performance. Derek?

Thanks, Terry. ONEOK's fourth quarter net income was approximately $91 million or $0.43 per diluted share, including $22 million or $0.11 per diluted share of noncash charges related to the wind-down of the energy services segment and costs related to the separation of ONEOK's natural gas distribution business into ONE Gas. In the fourth quarter of 2013, energy services recorded a $5 million after-tax net noncash charge as we continued to release capacity contracts to wind down the business, and paid approximately $12 million related to previously released transportation and storage obligations. Also in the quarter, ONEOK incurred a noncash after-tax charge of approximately $10 million or $0.05 per diluted share and expenses of approximately $7 million after-tax or $0.03 per diluted share, both onetime items related to the separation. Excluding these onetime costs, ONEOK's fourth quarter 2013 net income would have been approximately $113 million or $0.54 per diluted share. ONEOK's 2013 net income was approximately $267 million or $1.27 per diluted share. These results include noncash after-tax charges of $87 million or $0.42 per diluted share associated with the energy services segment wind-down and the previously mentioned noncash after-tax charge of approximately $10 million or $0.05 per diluted share in after-tax expenses of approximately $9 million or $0.04 per diluted share, both related to the ONE Gas separation. The energy services charges for the year were $139 million on a pretax basis, and its cash payments related to the release contracts were approximately $18 million. We expect future cash payments associated with the released transportation and storage capacity from the wind-down to be approximately $80 million on an after-tax basis through 2023. 2014 cash payments are expected to be approximately $33 million on an after-tax basis, which is included in our 2014 financial guidance. In 2013, ONEOK received…

Thank you, Derek. Let's start with our former natural gas distribution segment, whose fourth quarter 2013 earnings benefited from new rates, which were more than offset by higher operating costs and onetime charges related to the separation into ONE Gas. The energy services segment's fourth quarter 2013 operating loss was higher than the same quarter in 2012, and reflects the noncash charges related to the wind-down of the segment, which is expected to be completed by the end of the first quarter 2014. At ONEOK Partners, the natural gas gathering and processing segment's fourth quarter operating income was slightly lower. It benefited from higher natural gas volumes gathered and processed, offset by lower realized NGL product prices and higher operating costs and depreciation expense due to completed capital growth projects. Natural gas volumes gathered and processed continue to grow, driven by increased well connections in the Williston Basin as a result of more efficient drilling programs. While the absolute number of Williston Basin rigs has decreased, multi-well pad drilling has increased significantly. In addition, the quality of the producing acreage yields some of the highest returns in our producer's portfolios. Also, the transition to a manufacturing mode from exploration continues to accelerate. We expect to see continued drilling in the Williston Basin as more than 90% of the economics come from crude oil production. We connected 210 wells in the fourth quarter and 1,160 wells in 2013 compared with 940 wells in 2012. And we expect to connect approximately 1,300 wells to our Williston Basin and Mid-Continent gathering systems in 2014. We experienced extreme weather conditions in the Williston Basin and Mid-Continent in December that marginally affected our processed volumes, which increased by almost 25% in the fourth quarter of 2013 compared with the same period last year. We plan…

[Operator Instructions] And our first question will come from Carl Kirst with BMO Capital.

I've got a micro question maybe on hedging and then, maybe more of a macro question. And just happened to notice that the NGL price realizations in the fourth quarter, for instance, were a little sequentially down from third quarter with the market, I think, sort of more advancing. I didn't know if that was basically just due to entering fourth quarter with, essentially, just a full-hedged profile. I just wanted to confirm that it was that versus say, for instance, perhaps wider structural basis being experienced?

Carl, you're correct, that's exactly right. We came into the quarter fully hedged, basically, and so the prices that were carried into the quarter, obviously, were slightly lower than where the actual market turned out for the quarter.

No, understood. Appreciate that. And so as we look at say, for instance, fourth quarter and you all obviously ratcheted up prudently the hedging profile for 2014. Is that something that we should take as roughly equal through the year or is it something where again, maybe -- because there has been so much price volatility in the first quarter, should we be thinking that the first quarter is already fully hedged out at that same level? I just didn't know if there was maybe any additional color you could provide there.

Yes, Carl, I think that would be a true statement. We've been fairly levelly hedged throughout the year, so I think that's right.

Okay. And then lastly, and I understand this may be more challenging to answer, given the volatility that we have seen in the first quarter. I didn't know if there was any additional color you could provide on optimization opportunities in the first quarter. I think there may be desire to look back on some prior years given how well the optimization had done in periods of volatility, by the same token, with the exchange services ramping, there would seem to be not quite the same exposure. And then with Sterling III kind of now coming in, in March, maybe there wasn't the same opportunity to, perhaps, capture those spreads. So I didn't know if there was any color you could provide as far as what the market should be expecting or not expecting given the volatility.

Well, Carl, we can't give you -- we can't talk about first quarter financial performance, obviously, but what we can do is talk about what happened in the first quarter. What were the market responses, if you will. And really, what we saw in the first quarter was just unprecedented demand driven by going into the winter, obviously, with low inventories and an unusually cold winter. We've seen producers have an increased desire to move their production to Mont Belvieu, that -- I mean, obviously to take advantage of more attractive prices at Belvieu. So that all equated to what we saw, a shortage of propane. January, February, heavy demand. Coal has subsided, though, as we look at the market currently. Prices are now -- we got trading today back down below $1.20 a gallon and clearly, the market has demonstrated that it's getting the volume that it needs and at least as far as how it relates to ONEOK, certainly, we were able to utilize the flexibility of our assets to make sure the propane got to where it needed to go. And as far as we're aware, there are absolutely no customers that did without propane during this season. So that's really about all I can say. I think the propane demand will continue to be somewhat robust, as we move into the year, certainly, as we go into the fill season. We won't see prices back at these levels during the year. We will see prices certainly moderate. So I think 1 of the key things, too, that I'll say is that we'll see more propane supply come online during the year to satisfy the market -- market needs. So we feel pretty good about where we are with respect to the propane markets. Does that help you?

No -- it does, and I understand you can't talk about the first quarter at this point but I do appreciate all the color.

Our next question will come from Ted Durbin, Goldman Sachs.

So I want to talk a little bit about, you've cited this favorable NGL product price differentials as being helpful to you. I'm just wondering if you can give us a little more commentary around that, is that just sort of a normal butane to isobutane spread, or where are you benefiting from the price differentials.

Sure, I think, well -- as far as the location differentials, for the Conway to Belvieu, I think we've guided you to about $0.07 to $0.08 a gallon and so that's what we expect for the balance of the year. I think in the iso to normal spread, we're in that $0.10 to $0.15 a gallon range for the balance of the year. So I mean, compared to last year, we see significant improvement in that iso to normal spread, I think we averaged less than $0.05 last year. So this year, we are looking for some improvement.

Got it. Okay, so it's really on the prices itself of iso to normal, it's fine. And then next question for me was just in the Bakken itself, the outlook here for -- the need for additional processing plants up there, how you're thinking about the contract structure if you were to go forward with that, maybe just talk about your plans in the Bakken.

Sure, Ted. Well, as far as the contract structures, we don't anticipate any changes at all. We continue to enter into acreage dedications with percent-of-proceeds contracts with a fee-based component. In certain areas where there might be heated competition, we may have to flex that percentage upward a bit but, for the most part, we've been able to stay pretty much in line with the historical percentages that have supported these -- the past capital investments for the future.

Got it. And then how are the conversations going around the need for additional processing? Obviously, a lot of flaring going on up there.

Yes, I mean, we continue to have a lot of flaring going on. We're doing a pretty good job up there keeping the flares in line. We're actually -- we're at about 30% flaring within our footprint. Even in the midst of just tremendous growth that we've experienced, producers have a very high sense of urgency to get these flares put out and to reduce the flaring levels. We've got a targeted expectation of around 10% to 15%, going from 30% to 10% to 15% over the next couple of years. So yes, a high sense of urgency and as a result, it's certainly increasing the need for more processing capacity and gathering systems.

Got it. And then if I could just ask 1 more. The operating cost here, particularly in the gathering and processing segment, looks like they've continued to tick up pretty quickly. I'm just wondering if we should think of this as continuing to go up here as you add the new processing plant capacity, are there some maybe operational synergies that we should see as you bring on additional plants and you're able to do some shared services or whatnot, let's say, in the Bakken?

Well, Ted, yes. Some of our operating costs, and I'm going to let some of these other guys talk about this, but some of our operating costs are kind of more fixed. And so you're feeling that right now. Now as we load these plants up and fill that capacity, there will be less and less incremental operating cost to go against that revenue. So yes, I mean, we don't -- nothing here surprises us from an operating cost standpoint and so what I'm saying is, is on a per unit basis, we'll see those operating cost continue to drop as we fill these plants.

Our next question will come from Jeremy Tonet, JPMorgan. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: I was just wondering, after the OGS spin, if you could provide any updated thoughts on -- does this change ONEOK's appetite for strategic or transformational acquisitions? Just any thoughts you have on M&A would be great.

Sure, I'd be glad to. Certainly, as I said in my remarks, ONEOK is a different company today. And our strategy certainly, in terms of maximizing the dividend, is to do of course, in fact, that and to operate this company as more of a holding company. And our strategy is for our M&A opportunities to be done at ONEOK Partners. And so I don't see ONEOK considering M&A opportunities that we can't keep blinders on. We can't ignore the fact that we've got a great currency at ONEOK, but as we sit today, our strategy is pretty straightforward. And at this point in time, I don't have any intentions of pursuing M&A opportunities at the OKE level. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: Okay. That's helpful. And I was just wondering if you might be able to provide a little bit of color as far as CapEx timing throughout the year. It seems like there's a lot of projects that could be coming out early in the year. Is that CapEx more weighted towards the front end?

Actually, for 2014, our CapEx spend is going to be weighted more toward the back end. Those projects that are coming online early in 2014, their capital spend is winding down of course, but then we've got other projects that are coming online during the year and that will heavily weigh the capital towards the back end.

Our next question will come from Ethan Bellamy, Baird. Ethan H. Bellamy - Robert W. Baird & Co. Incorporated, Research Division: How is the Sage acquisition tracking versus to your expectations at the time of purchase?

Well, the acquisition actually is going very well. We're having considerable success at signing up new acreage dedications from producers. We've generated a lot of interest. Certainly, as you'll recall, as we've said many times before, this is a significantly underserved basin which fits well for us, having the ability to not just gather and process gas but, as importantly, transport natural gas liquids out of this basin. So because of that flexibility, we're able to generate a lot of interest in and have a lot of success at signing up customers. So it's going very well. Ethan H. Bellamy - Robert W. Baird & Co. Incorporated, Research Division: That's good to hear. With respect to your 2014 guidance, can you give us the delta that you would expect from -- if you did not reject ethane this year?

We actually have not provided that level of detail. So I can't really comment on that. So that's about all I got to say about that. It's only I can't say anything. Ethan H. Bellamy - Robert W. Baird & Co. Incorporated, Research Division: All right. What impact, if any, has there been, positive or negative, on the timing or the amount of maintenance capital spending due to weather?

Well, good question. There really has not been that much impact from weather as it relates to the maintenance capital spending. The weather's occurred over such a very short period of time, so it really hasn't impacted us. I think we've probably been more impacted by our decisions as it relates to discretional capital spending. So there is a tranche within all of our maintenance capital budgets of discretional spending that we may choose from time to time during the year to do or not do. And we had some of that this year, and that's one of the reasons why our maintenance capital is lower. Ethan H. Bellamy - Robert W. Baird & Co. Incorporated, Research Division: Okay. Last question. Should we be worried about any issues with natural gas pipeline volumes and just maybe Northern Border or anything long-term? Obviously, that's been a big question for the industry.

Really, as it relates to our assets, all of our assets, including Northern Border, are market connected, direct-market connected. And they don't really -- they aren't really exposed to the classic basis spreads that you might see from other pipelines that are kind of more hub-connected. So the end-user customers have to have the gas. They've got to have the gas and, in many cases, they don't have economic alternatives. So in that scenario, they need the service. So from a re-contracting standpoint, we really don't anticipate any problems. In particular, in the case of Border, it's a very low-cost provider, so it's extremely competitive in the marketplace, as are the rest of our assets. So they're very well-connected, they meet specific customer needs. So when we get to the point in time where we renew contracts, we generally don't have any problem renewing them, certainly, as long as the rates and the fees we charge for the services are fair. From a macro perspective, our typical contract life is about 7 years across all our inter-states and intra-states. So we're really in pretty good shape.

Our next question will come from Chris Sighinolfi with Jefferies and Co.

I was just hoping to hit real quickly on a couple of points. Carl had asked about the NGL price realizations, I was curious if you could add some color to what happened on the condensate front. Seemed like a very similar sort of step-down. We obviously saw natural gas do sort of a similar head fake last quarter and you explained it was related to some acute issues in the Bakken. I was just curious if you could comment on the condensate front.

I think some of it's the same as what you -- what I indicated to Carl, but I think, in particular, why you see a lower condensate price is in that realized price, we have transportation cost that are netted out. Okay? And so in the case of condensate, we'll see anywhere from a $10 to $15 a barrel transportation charge applied to that net realized price. So that's why you can't get that price to really correlate to the WTI posting. Does that help you?

Got it. Yes, it does. That's very helpful. And then I guess, 1 comment obviously, a lot of commentary about what NGL pricing supply and demand trends have meant for the ONEOK assets and sort of responded to the market. I was wondering, within that, given the strong propane price particularly in Conway in 4Q and thus far in 1Q, what have you seen ethane rejection wide across the system? Does that sort of create a corresponding desire to recover more in order to boost up the propane yield? Can you comment about that?

Yes, Chris, that's a great question. We really have actually not seen that. We've actually seen a slight, ever so slight, increase in the amount that we're rejecting, actually. Part of it is from new supplies that we're connecting that are not recovering ethane. So our impact from ethane rejection, actually, is slightly higher. Do you understand what I'm saying? We haven't seen ethane come off but what we've seen is, from the new supplies that we've connected, they're not coming out of the box recovering ethane.

Understood. So on a total basis, the implied rejection number then ticks up.

Correct. That's correct.

Okay, understood. And then I guess, a final question for me. Can you give a little bit of color around the delay for Sterling III, sort of, I know you still had, at least in the last press release, some capital to deploy on that, you were saying March in-service. Just an update on that and update real quickly on the outage you had at the Belvieu frac and -- I think that was a planned outage in January, just if everything went sort of to plan on that. And then a reminder on Sterling I, just the size of that pipe.

Chris, we'd be glad to do that. I'm going to let Wes Christensen take that Sterling III and Mont Belvieu frac question.

Sure. The Sterling III pipeline construction was primarily delayed due to the weather conditions we had, from both rain and snow hindered the construction during the primary [indiscernible]. In the Mont Belvieu area, we took a -- we started in the east to up. It gave us capacity, it allowed us to take a scheduled outage for maybe 1 complete planned maintenance.

A little difficult to hear but I'll look for the transcript for full details.

Our next question will come from Helen Ryoo, Barclays Capital.

Terry, I appreciate your color on the NGL market and I realized that it's difficult for you to comment on Q1, but just so that I understand in general how your optimization business works. Are you limited by your physical capacity to move products from 1 hub to the other or does some part of your optimization business entail barrel exchanges and, therefore, you're not limited by actual -- the amount of barrels you have to move around?

Well, it's a combination of all those things, Helen. We are, in fact, affected by and limited, not just by the capacity of the pipelines themselves, as we have multiple diameter pipes between the Mid-Continent and the Gulf Coast. The other thing that affects us to capacity is the type of product, what products you're actually moving and to where. So that can affect you as well. The heavier the barrel, the more difficult it is to pump those barrels, it requires more horsepower per mile. So that will affect you as well. And we had extreme demand and certainly, when you have periods of extreme demand, you may or may not be able to meet, on an hourly basis, the delivery rates that are required. So we did have some of that.

Okay. And does it matter, in general, which hub has a higher price, let's say, like in this quarter, Conway propane's so much higher than Belvieu but in the past, it was always the other way around. Does it matter which hub has a higher price? Or as long as there is a decent spread, I mean, is it the absolute level of spread that matters more?

Helen, I'm going to let our resident expert, Sheridan Swords, answer that question.

Helen, I think the answer is, is that our systems are designed to move barrels from Conway to Belvieu because as you've said, historically, that's been a higher price. So it's actually more advantageous for us most of the time if Belvieu was higher than Conway.

Okay. But I guess, given that you have these projects coming online, I mean, with Sterling I and II having bi-directional capability, does that change the ability or not really?

Actually, only Sterling I has bi-directional capabilities. So you are limited, even if that was the choice to do that, you would be limited by that capacity.

Okay. Got it, got it. That's helpful. And then just switching on to your comment on these 10 more -- 10-plus processing plants that are being connected to your system during 2014, are these plants like solely connected to your system. Are you guys the sole sort of NGL take-away solutions for these new plants or are they connected to, I guess, other third-party lines?

These plants will be solely connected to our system.

Okay. Great. And then just lastly, what's the size of the ATM program you have in place?

It's a $300 million program.

Have you used any of that?

We have. We've used a little bit during 2013, we just kicked that off during 2013. I think I said in the last quarter of March that we expect to use that a bit more heavily in 2014.

Our next question will come from Becca Followill, U.S. Capital Advisors.

Could you talk a little bit about your expectations, whether or not there's any changes in your expected volume growth in the NGL segment for gathered volumes to be up 13% and frac volumes to be up 8%, given that volumes were down sequentially and that 2013 came in a little bit below guidance?

I think the answer to your question is that, that fractionated volumes are down because we frac some barrels that we don't gather, especially coming off of OPPL. So we saw a bigger decrease in volume coming off of OPPL. We continue to think that we will meet our guidance for 2014 with the new plants that are coming on, which most of them we will be gathering as well.

And then can you discuss on those 10 plants that are coming online, what's the capacity of the those plants?

They range from 50 million to over 200 million.

But in total, do you have that capacity?

Becca, I don't have them off the top of my head right now, what they all total up to be.

And then last question is, you guys have a meaningful storage position in the Mid-Continent area to store LPGs. Can you talk a little bit about how this winter's shortfall or extreme conditions have impacted producers' decisions to maybe contract down the road? Is that storage normally full? What happens to rates as a result of this?

The storage season -- Becca, the storage season that we're coming into usually starts about March when we start re-contracting, and that goes through April. It's kind of the season for the next year of re-contracting. So we will see as we get into that time period if this winter has changed the appetite of the end users on the propane side for more or less storage.

So it's just too early to tell at this point?

Yes.

Our next question will come from Craig Shere, Tuohy Brothers.

So kind of a follow-up question here. Given your existing contracts structure and the capacity of existing Sterling pipelines, I and II, does the capacity to take advantage of the bi-directional nature of Sterling I, in other words, reverse-flow north, increase when Sterling III comes online?

Sheridan?

No, it does not.

Okay. And can you provide some color around trends in bundled NGL services from the Bakken down to Belvieu, maybe something directional, though not absolute in nature as a response, like the proportion of -- that such business represents at contracted capacity that's on the Bakken NGL line now or, say, on the Sterling lines now down to Belvieu.

Craig, I'm going to take this question at a high-level, then Sheridan can kind of clean it up but the barrels that we move out of the Bakken, you understand, originate from our own processing plants. Our third-party volumes will grow. So we've contracted those volumes at competitive rates. That business, because it is some of the longest haul business that we've got, that is, those barrels are the farthest away, we move those barrels through multiple pipes and fractionation facilities. Those will be some of the highest per-unit margin barrels that we move. So from a revenue standpoint, much like the margin we generate in the Bakken, these will be some of the highest-margin barrels and most valuable barrels yet the volumes are going to be, relatively speaking, small. So to get to your question, they're not going to take up a whole lot of capacity in the downstream infrastructure relative to movement, say, out of the Mid-Continent or other parts of our system. Sheridan, anything?

I don't have anything to add to that.

So just as a follow-up. I think historically, 1 of the concerns the market has had is that on the optimization revenue, it was always a little unclear, for commercial proprietary reasons, what was available and obviously no one knew the future and so there wasn't much of a multiple put on those types of revenues and of course, you didn't distribute them when you got windfalls. But to the degree you're able, over time, to make this a little more of a bundled, less volatile, more bundled fee-based type business as far as these spreads between basins or hubs then, obviously, you should get more of a multiple on that. Are you saying that, though the Bakken margins are very high, that it's never going to substantially de-risk some of these basis points?

Okay, Craig, let me try and address your question this way. We have had, for some time, and we've been very open about this, a strategy to reduce our exposure to that Conway to Belvieu spread, i.e., our optimization business. We've been very successful in doing that, in contracting that capacity under fee-based contracts. And I guess, included in some of that is that the Bakken barrels move through some of that capacity. What's happened during 2013 is the ethane rejection created some available capacity that we wouldn't otherwise have. So as a result, we took advantage of that available capacity and captured whatever spread was there, okay? So generally speaking, I mean, we are making very good headway with taking that volatility out and our associated dependence on that spread.

Okay. And there's still a market for long-term contracting regardless of the level you have currently in the very high-single digits, maybe upwards of $0.10, in Belvieu and Conway?

Sheridan's looking at me, I'll let him handle that question.

I think the answer to your question is, as we look at our bundled service, if we have a customer that wants to go down the Mont Belvieu, it all comes down to where they're located out on our system to determine what the rate's going to be and what the competitive position they're in at that time.

[Operator Instructions] At this time, there appears to be no further questions in queue.

Thank you for joining us. Our quiet period for the first quarter starts when we close our books in early April and extends until earnings are released after market closes on May 6, followed by a conference call on May 7. We'll provide details of the conference call at a later date. I'll be available throughout the day to answer your follow-up questions. Thank you for joining us, and have a great day.

Thank you. Once again, that will conclude our call for today. Thank you, all, for your participation. You may now disconnect.