Ladies and gentlemen, good day, and welcome to the ONEOK and ONEOK Partners' First Quarter 2013 Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you. And welcome to ONEOK and ONEOK Partners' First Quarter 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 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 is John Gibson, Chairman and CEO of ONEOK and ONEOK Partners. John?

Thank you, Andrew. Good morning, and many thanks to all of you for joining us today. As always, we appreciate your continued interest and investment in ONEOK and in ONEOK Partners. Joining me today are Derek Reiners, our Chief Financial Officer; and Terry Spencer, our President. Also on the call and available to answer your questions are Pierce Norton, Executive Vice President of Commercial; and Rob Martinovich, Executive Vice President of Operations. Today we will review the first quarter 2013 financial results; review our progress on our growth projects, including projects completed and about to complete; and finish with some comments about our backlog and future growth projects. So let me start with our first quarter performance. Both ONEOK and ONEOK Partners' first quarter results were lower on a quarter-over-quarter basis. The partnership's earnings were lower primarily because of reduced NGL optimization margins, lower NGL volumes due to ethane rejection and lower realized commodity prices. And I'll provide a bit more color on that in a moment. On a positive note, the partnership continues to see the volume growth we expected in both the natural gas liquids and natural gas gathering and processing businesses as a result of our completed capital projects. And that volume growth will continue as volumes from the new Stateline II natural gas processing plant and, of course, the Bakken NGL pipeline ramp-up. ONEOK's natural gas distribution segment turned in slightly higher results for the first quarter, reflecting higher rates, offset partially by higher share-based expenses. And our energy services segment reported a loss, although lower than the first quarter last year. This segment continues to face headwinds due to both low natural gas prices and volatility. As Terry will explain to you in more detail in his remarks, the partnership's NGL segment had a $90…

Thanks, John, and good morning. ONEOK's first quarter net income was $113 million or $0.54 per diluted share compared with $123 million or $0.58 per diluted share for the same period last year. As a reminder, first quarter 2012 net income included $14 million or $0.07 per share from ONEOK's retail marketing business that was sold in February 2012. ONEOK Partners' results were lower in the first quarter compared with the same period last year due primarily to narrower NGL location differentials and lower realized NGL prices, offset somewhat by higher volumes mainly in the Williston Basin. The natural gas distribution segment posted higher results due to increased rates, offset partially by higher operating expenses. The energy services segment continues to face a challenging market. However, its results improved compared with last year's first quarter. ONEOK reaffirmed 2013 guidance with net income expected to be in the range of $350 million to $400 million and we have not made any adjustments to our 3-year guidance provided in February. In April, we declared a dividend of $0.36 per share, unchanged from the previous quarter. Subject to Board approval we expect to increase the dividend $0.02 per share in July and, as mentioned in our year-end conference call, we will reevaluate our dividend if market conditions improve. In the first quarter, ONEOK received $131 million in distributions from ONEOK Partners, a 43% increase from the same period last year. ONEOK's first quarter 2013 standalone cash flow before changes in working capital exceeded capital expenditures and dividend payments by $125 million. We currently are and have been benefiting from bonus depreciation that was extended in January but we do not expect this benefit to continue after 2013. The resulting effect is that our cash payments for taxes are expected to rise in future years, thus reducing our free cash flow. Our slightly lower 3-year dividend growth rate announced in February reflects both the revised cash distributions anticipated from ONEOK Partners and our expectations about higher future cash taxes. We still expect to generate significant free cash flows in the future, which will be available to consider increasing the dividend, acquiring additional units of ONEOK Partners and/or repurchasing ONEOK shares. As we have said many times, we will consider each of these alternatives at the time but they are not mutually exclusive. ONEOK's liquidity position remains strong. At the end of the first quarter on a standalone basis, we had $551 million of commercial paper outstanding, $75 million of cash and cash equivalents, $647 million available under our $1.2 billion revolving credit facility, which we amended in March, extending the maturity to 2018. Our standalone debt to capitalization ratio was 45%. Now Terry will update you on ONEOK's operating performance.

Thank you, Derek, and good morning. Let's start with our natural gas distribution segment. As you saw in the news release, first quarter 2013 earnings were higher compared with the same period last year, reflecting higher rates in Oklahoma, Kansas and Texas. Operating costs were higher compared with the first quarter 2012 primarily because of share-based compensation expenses due to the appreciation of ONEOK's share price along with increasing pension expenses and property taxes. While energy services' earnings are up compared with the same period last year, it continues to experience challenging market conditions. In the first quarter, this segment realized an operating loss of $4.4 million compared with a loss of $30.7 million first quarter of 2012. We did see a reduction in storage and transportation costs of $7 million due to the reduction in our leased storage capacity. We have 53 Bcf of natural gas storage capacity under lease at the end of this quarter compared with nearly 76 Bcf at March 31, 2012. John, that concludes my remarks about ONEOK.

Okay. Thank you, Terry. Now Derek will review with you the ONEOK Partners' financial performance and then we'll go back to Terry. He'll take a look at the partnership's operating performance, the growth projects and then give you a brief update on our view of the current and longer-term NGL market.

Thanks, John. In the first quarter, ONEOK Partners' net income was $157 million or $0.42 per unit compared with $239 million or $0.91 per unit in the first quarter of 2012. Distributable cash flow was $193 million in the quarter compared with $279 million in the first quarter of 2012, resulting in a coverage ratio of 0.81x for the first quarter, 2013. By comparison, our coverage ratio is 1.74x in the first quarter of 2012, when we realized higher NGL optimization margins benefiting from a $0.24 per gallon Conway-to-Mont Belvieu ethane differential, compared with a $0.01 per gallon differential in the first quarter of 2013. As we said then, we did not believe the wide NGL location price differential was sustainable and, as a result, did not raise our distribution to unitholders, which is why the coverage ratio was so high. Our long-term annual coverage ratio target remains at 1.05 to 1.15x. However, as we discussed in our year-end earnings conference call, we expect our full year 2013 coverage ratio to be less than our target but still greater than 1x. We reaffirmed 2013 net income guidance range of $790 million to $870 million and distributable cash flow range of $910 million to $1.0 billion and we did not make any changes to our 3-year growth forecast that we provided on February. We increased the distribution declared by $0.005 per unit for the first quarter of 2013, an increase of 13% from the first quarter of 2012. Subject to Board approval, we expect to increase our distributions by $0.005 per quarter for the remainder of 2013. In the earnings release, you will note some updates in our hedging information. NGL hedges increased to 64% of our expected equity volumes for 2013. Condensate hedges remained at 83%. And 78% of our…

Thank you, Derek. As John noted, the biggest contributor to ONEOK Partners' quarter-over-quarter earnings decline was significantly narrower NGL location price differentials between the Conway, Kansas, and Mont Belvieu, Texas, market hubs, driven largely by our industry's current high ethane inventory position. I'll provide more color on these market dynamics in just a few minutes during my review of segment performance. The natural gas gathering and processing segment's first quarter financial results were lower due primarily to lower realized NGL prices and higher compression and operating costs due to the projects we placed in service over the last year, partially offset by higher natural gas volumes gathered and processed. Natural gas volumes gathered and processed continue to grow, driven by increased well connections in the Williston Basin and Western Oklahoma. For the first quarter, natural gas volumes gathered increased 16% and natural gas volumes processed increased almost 30%, driven by the new Garden Creek and Stateline I natural gas processing plants and related infrastructure projects completed in 2012. Both the Garden Creek and Stateline I natural gas processing plants are operating near their 100 million cubic feet per day capacity. Stateline II, which was recently completed, is expected to reach capacity later this year. We expect to connect more than 1,000 wells to our gathering systems in 2013 in both the Williston Basin and the Mid-Continent. That will enable us to achieve our volume expectations this year. The first quarter was a bit challenging on the well connection front due to inclement winter weather conditions. Despite those challenges, we still connected 270 wells in the quarter compared with 200 wells in the first quarter last year. The flaring of natural gas in the Williston Basin continues but, in the areas we operate, flaring is decreasing, so our new infrastructure is…

Thank you, Terry. Before we take your questions, I'd like to just spend a few moments to provide you with some additional comments on our future growth projects. For the last year or so, we've communicated a $2 billion plus backlog of unannounced projects and, during that same timeframe, we've announced $1.5 billion of new projects but the backlog remained unchanged. As Terry discussed early, the partnership's current project backlog is now $2 billion to $3 billion and I'm confident that, over time, we will add to that backlog just as we have in the past. We have always chosen to not discuss publicly the specifics of the projects in our backlog, primarily for competitive reasons. Even though we won't provide insight into the type of projects we're working on and their specifics, I can tell you that we are not interested in acquiring assets or developing projects that involve exploration and production, refineries, petchem or petrochemical crackers, electric power generation, retail marketing of CNG or heavy truck transportation. Every one of our projects starts by understanding the supply and demand of hydrocarbons and where we have a sustainable competitive advantage to provide the assets or services necessary to connect supply with demand. As Terry mentioned, we will continue to grow in our current businesses and our projects are always focused on applying our core capabilities to create value for our customers and our company. In closing, I'd like to again, thank you -- thank our more than 4,800 employees, whose dedication and commitment allow us to operate our assets safely, reliably and environmentally responsibly everyday and create exceptional value for our investors and our customers. Our entire management team appreciates their efforts to make our company as successful as it is today. Operator, we're now ready to take your questions.

[Operator Instructions] And we'll take our first question from John Edwards of Credit Suisse. John Edwards - Crédit Suisse AG, Research Division: I just wanted to follow up with a question kind of on the NGL market outlook. I guess I'm trying to figure out -- I mean, we kind of share your view, I guess, if you look at the petchem market being relatively robust in the 2016-and-beyond timeframe but we figure the market probably to be more balanced. I think you said you thought it would be ethane undersupplied at that time but we figure the steam crackers wouldn't get built if it were undersupplied. So I'm just wondering -- I'm just trying to figure out how to reconcile the comment, where you were thinking it would be undersupplied in the future as opposed to, say, more balanced?

Well, that's a great question, John. I think that when you look at this over the long term and when we sit down and talk to these petrochemical companies, they recognize as you look at what's being developed today and you look at the potential demand for another 700,000 barrels a day for ethane as you reach this 2017 timeframe, they recognize that there's a potential for an undersupplied situation. However, they recognize, too, that there's a lot of potential in these shale plays and that there is a lot of capacity being developed upstream and that the midstream companies are going to do what they need to do to make that supply materialize. So the projects, at least as they're indicating to us, are going to happen and the fact that we're painting this picture of an ethane undersupply doesn't seem to affect them one bit in terms of their psychology. John Edwards - Crédit Suisse AG, Research Division: Okay. So the belief -- I guess, to clarify, the thought process is that the -- with the demand being significant that really, as prices improve, the supplies -- it may not be on an announced project base at this time but it's likely to come? I mean, it seems to us every time there's any kind of price recovery, more ethane comes to market, which is why it looks to us we're in a sort of prolonged oversupply situation until these petchem projects come online. Is that kind of the thought process?

I mean, certainly in the near term, we feel that way. In this 2014 to 2015 timeframe, there's going to be continued demand creep and we've seen it as recently as this first quarter. We've seen 50,000 barrels a day of incremental ethane demand come from some expansions that have started up. So the experts continue to see this happen. The other thing that's going to happen, particularly with propane prices running up with the export demand, you're going to see this switchover from propane to ethane occur. And that happened significantly in the first quarter. So as you move into this 2014 timeframe, we think the markets are going to be more balance. And it's not really going to be until you get into that 2016 and 2017 timeframe, where we're going to be kind of behind the 8 ball. The thing you've got to remember, too, with these petrochemical companies is the demand pull they're seeing on their side for ethylene in the world market is huge. The spreads that they're realizing are off the charts. And so it is going to take something extremely major to get them to change their minds in terms of building and continuing to build out these world-class crackers.

Our next question comes from Michael Blum with Wells Fargo.

Just a couple of quick questions for me. One, it seemed like your operating expenses just kind of across-the-board, particularly the NGL and G&P segments, was up quite a bit. Was there anything just kind of unusual going on there? Or should I be viewing that as kind of new normalized levels, given the amount of investment you've made?

Michael, at a high level, I mean, certainly we're bringing on these new processing plants and so we're going to incur increased operating expenses. So our per unit operating expenses are going to be higher. But until we get the volumes behind these plants -- I mean, when you operate a processing plant, it costs you about the same amount of money to operate a processing plant that's at 25% load as it does to operate one that's at 100% load. So you're going to -- as you ramp up, you're going to go through this period of higher per unit operating cost on the front end because you're bearing the full load. Then on top of that, you're bearing depreciation and then interest expenses and the whole nine yards, okay? So until we get these plants full, which we expect to do later on this year, you're going to see these higher per unit costs. And as we fill that volume up, the per unit operating cost will go down.

Okay. That's helpful. Did you see any weather disruptions in the first quarter that had a material impact on results?

Michael, we always see winter in the Bakken. So we had some pretty significant inclement weather that affected us really more from a well connect standpoint. Not much of an impact, though, from an expected revenue standpoint. We had severe weather, I think, the quarter a year ago. So I mean, it's to be expected. So I'm not going to bellyache about 24 inches of snowfall.

Got it. Okay. And my last question on energy services. Given the increase in natural gas prices and we've seen, at least in some areas, a widening of basis differentials, is it fair to conclude that, that'll result in some uplift in that business? I mean, are you able to capture some of that change in the market?

Michael, this is Pierce. Actually, the biggest impact that we're going to see in energy services is due to expiring contracts on the transport and storage side. We're going to be reducing about $29 million year-over-year. That's going to have a bigger impact. We're still seeing pressure on the winter-summer spreads, as well as the location spreads.

Your next question comes from Becca Followill with U.S. Capital Advisors.

On the NGL segment, can you talk a little bit about where you see volumes going across the year relative to ethane rejection? I think you said you were seeing roughly 90,000 barrels a day of ethane rejection yet the NGLs distributed fell by about 140,000 barrels a day. Can you kind of reconcile that difference there and then where you see volumes ramping up across the year, if any? And also on the fractionation side, talk a little bit about the reduction relative to the fourth quarter and how you see that ramping up across the year.

Well, I'll take the first part of your question, Becca. The 90,000 barrels a day is what we're expecting for pretty much most of this year. We don't really see that changing. We've seen ethane prices and natural gas prices move around a lot in this first quarter. But the volume of rejection has really stayed fairly steady. So we really don't expect a change. From a residue standpoint at these processing plants, the pipelines seemed to be just fine taking the natural gas, so there's not any significant quality issues that we've seen. So we expect that level to stay around the 90,000 barrels per day. And then to your other question, Pierce, do you want to grab...

I mean, the only thing that I would add to that, Becca, is that we will see significant volume growth in the Williston Basin. We're averaging about 261,000 a day currently and we have capacity up there to process 400,000 a day. So as Terry indicated, we expect to get those plants filled up more towards the end of the year, so you're going to see significant growth in the Williston. We also will see growth from third-party plants that affect our NGL business down in the Mid-Continent as they come on. Fractionation right now is running slightly higher than what it averaged in the first quarter, so we expect that to be there. And then like Terry said, we do expect the ethane rejection to continue through the end of the year.

But can you reconcile the 90,000 barrels a day of ethane rejection versus the roughly 140,000 barrel a day reduction in NGLs distributed from the fourth quarter to the first quarter?

Becca, I think that maybe this might help. One of the other things that we expect to happen is, in the third quarter of 2013, we're going to be starting up that MB-2 fractionator. So we'll see a significant ramp-up in NGL volume when we start that facility up. So that might get you part of the way there.

And our next question comes from Craig Shere with Tuohy Brothers.

A couple of quick questions. I know you don't historically talk about the size of the Conway-to-Belvieu optimization capacity you have open. But as you work to bring this down, focusing more on fee-based earnings, can you quantify the ramp-down over time maybe in percentage ranges?

Craig, we really haven't given any kind of forward looks on what that ramp-down is. But I mean, you can look at our margins and see that there was a significant change in the exchange in storage and transportation quarter-over-quarter. So we still continue to think that's going to happen. One of the big movers is going to be when Sterling III comes online because we do not have that risk there that, that is contracted by volumes. So when that comes on, that can make a significant difference in the shift over the optimization volumes currently seen.

Okay. And have you altered your long-term view of what is the sustainable Conway-to-Belvieu spreads?

No, we haven't. We still -- as we've indicated for this year, $0.05 a gallon for ethane and looking in the $0.10 a gallon range as we move out to 2014 and 2015. We still feel strongly, as we've said many, many times before, we expect these spreads to narrow and they have narrowed. And they're going to move back into that cost-of-build range. And so certainly, our view over this next 2 to 3 years has remained at that level.

Okay. And last question. We're kind of getting into an unusual situation here with gas up another $0.09 today, where ethane rejection, which in recent periods had been driven more by low NGL prices, could be driven a little more in future periods by high gas prices. So can you speak to the relative impact of that? Since your low [indiscernible] on gas, it's obviously not quite the same impact as just having low ethane prices.

Right. I mean, when we look at natural gas as far as it affects our business, our gathering and processing business, we're well hedged at pretty attractive prices. When you look at our customers on the NGL front, certainly those spreads, the ethane spread in particular that you're referring to, affects their throughput. Certainly, if natural gas prices go higher, it could affect their economics. But we saw very low prices in the first quarter for ethane and our view is that if those prices -- as weak as those spreads were, that 90,000 barrels a day seemed to act like a floor.

The other thing to consider is most of those customers, NGL customers, have also hedged much like we have. So their economic decisions, for most case, have been made. I don't think we expect to see significant difference in the amount of ethane rejected due to the rising natural gas price for that reason.

But there's certainly the possibility of a prolonging of the trend. Isn't that correct?

Certainly, that's a possibility. I think that one of the things, too, that you have to keep in mind, too, is last year when you're talking specifically about natural gas, we saw significant coal displacement in the power generation sector. Just based upon what the experts are saying this year, probably not going to see that.

So to think about this, 2 different fronts. One is gathering and processing, rising gas prices help us. So we're good with that. The second thing is, theoretically, you're correct. Rising gas prices relative to NGL prices puts more pressure on the ethane rejection volumes. But as we look at the NGL customers that are on our system, most of them are fairly effectively hedged as it relates to 2013 and, really, into 2014. So we don't anticipate to the NGL segment a significant increase in the amount of ethane rejected than from our current levels.

And last take on this. Is a lot of the 2013 impact simply because of the Conway pricing and really not as much an issue when you start thinking about relative pricing on a Mont Belvieu basis between ethane and gas?

I believe that to be true. The first point is the one that we're trying to get across in our comments. And if you look back a year ago, our comments were along the line with this high coverage ratio and high ethane spread between Belvieu and Conway that we didn't think they were sustainable, so we didn't increase our distribution. We foretold that industry infrastructure would have the impact of narrowing that spread over time. And that has come to fruition. And during that time period and even before, I think you'll note that we've been looking to reduce the amount of volume we have that we utilize for optimization and that's the reason why. So I think on both points I'd agree with you.

And our next question comes from Elvira Scotto with RBC Capital.

Thanks for all the information, your thoughts on ethane markets near-term and longer-term. Can you maybe touch on your view as NGL production increases? How you see the heavier end of the barrel, supply-demand dynamics shaping up there?

Sure, Elvira. We do see supply growing on the heavier end of the barrel. In particular, you've heard a lot of discussion about normal butane being an issue. But one of the things that has been emerging, much like for propane, the export markets have been increasing, not just for propane but for LPGs as a whole. So the heavier end of the barrel, in particular normal butanes, are finding its way into the export pool as well. So as those volumes continue to grow, they will continue to drive attractive price levels in the international markets and find their way into the export pool. At least that's what experts are telling us.

Okay. Great. That's helpful. And then in terms of kind of expanding into crude oil, would you consider doing an acquisition to actually gain a foothold in that market?

Yes, we would.

And our next question comes from Helen Ryoo with Barclays.

Question on your fractionation volume, I guess. It came down quite a bit versus Q4. I'm just wondering, is that mostly Mid-Continent fractionators that took the hit there?

Helen, it's a combination of Mid-Continent and Rockies. And it's mostly ethane rejection.

Okay. So your Mont Belvieu fractionators really did not suffer volume decline?

We had some impact at Mont Belvieu, as well. Across our fractionators, we had impact.

Okay. But vast majority, you would say, is in Mid-Continent and Rockies?

Mid-Continent and Rockies. That's correct.

Okay. And I know a lot of your new projects come with 100% volume commitment and your new projects are mostly in the Mont Belvieu area. So as you think about having these new MB-2, MB-3 coming, should those fractionators be subject to volume risk? Or are they pretty much well protected because of the contracts?

Helen, they're pretty much protected from a volume standpoint because the vast majority of these contracts are, as you say, they're firm-based, frac-or-pay or ship-or-pay type contracts. So they're going to be pretty well insulated from volume risks. However, they won't start up chock-a-block full when we begin. But the revenue streams will be there.

Okay. So there's going to be some ramp-up period. But once you fill it up -- once you've reached a certain level, you should not worry about volume fluctuating?

That's correct. I think one other comment that I'll make as it relates to these firm contracts, and I've made this comment before, is not every one of these contracts is 100% firm. So when we negotiate these contract rates, there will be a very high percentage, 90% or so -- and I'm not going to give you details for competitive reasons. But there will be some high percentage of that contract that will be structured firm.

Okay. Got it. And then just another quick clarification. Did you say that because -- are you changing your NGL price assumption for the year? I know it started at $0.66. But what was your comment that now -- that you've realized $0.85 that, that's sort of the level that you're looking at for the remainder of the year?

Helen, the reason it came up to $0.85 is because the $0.66 was based on a full ethane recovery, and so when you -- in actuality, we're not at full ethane recovery because we're not recovering ethane in the Rockies or the Bakken. So when you calculate the weighted average composite price, assuming no ethane recovery in the Bakken, you'd come up with this $0.85.

And our final question comes from Ketul Sakhpara with TPH Asset Management.

A couple of quick questions. The new fracs that are coming up in Mont Belvieu, does this level of ethane rejection change the ramp-up schedule or the ramp-up schedule still remains relatively the same?

I didn't understand -- could you repeat that question? I didn't hear it all.

Okay. So does the ramp-up schedule get affected because of the ethane rejection, the ramp-up schedule for your new Mont Belvieu fractionators that are coming up online?

Yes, it will affect it. It will be affected by ethane rejection to the extent it extends -- ethane rejection extends into that -- during that period. But remember, as I've mentioned just on the previous question, much of that capacity is subscribed under firm, frac-or-pay contracts.

Okay. Do you think that ramp-up schedule is 12 to 18 months, above 18 months to get to 60%, 70% of the capacity? Have you given any color on that?

I think our expectation is to be full during the 2014 timeframe.

Okay. The shift from -- now moving to your optimization volumes. The shift from optimization volumes to fee-based volumes, should we see that in the NGL transported distribution lines volumes? Or where should we see those volumes show up?

Where you'll see it actually, and you've seen it actually in the financials that we produced for this quarter. Where you'll see it is in exchange services, okay? So like if you look at the quarter, we said $40 million improvement in exchange services quarter-over-quarter. Most of that is this recontracting that we're talking about. That's where you'll see it. But it'll be -- from a physical volume standpoint, you'll see it in your gathered volume and you will see it in some of your transportation volume, as well.

Okay. All right. And as more and more ethane is being rejected, the Btu content of gas keeps going up. Have you seen any issues with that content affecting the pipeline gas that is being shipped in terms of are they exceeding the maximum Btu content allowed on natural gas transportation pipelines on any of your systems anywhere or that's not an issue so far?

It's really not been an issue so far. I've not heard anything really significant in the way of downstream end users having to adjust their -- significantly adjust their operations to accommodate the ethane left in the gas train.

And our next question comes from Christine Cho with Barclays.

You talk about growing all of these businesses at OKS and just mentioned that you would consider acquiring crude assets to enter that market. It would seem to me that growing the utility business is very low on this list, given the growth for everything else is just better. How important is it to keep these assets maybe with respect to investment-grade rating? It seems like you would be able to pay the dividend no problem without these assets. So just kind of trying to get your thoughts on possibly divesting these assets, whether through sale or tax-free spin, to become a more pure-play EGP [ph]?

Well, as I've indicated before, that we at the Board level continue to discuss our structure and try to determine that ultimate and/or most efficient structure. Clearly, as you point out, most of our growth has occurred inside the partnership. We've not been successful in paying the values requested in the marketplace for distribution assets. We have said that we believe that the distribution assets at the OKE level do have a positive impact on our credit rating. So the answer to your question is we continue to look at that, from a Board's perspective, at what is the right structure. And we continue to come back to where we are today. But we can't emphasize enough how much we spend time looking at that and talking about it.

Okay. I guess, would you be able to keep your investment-grade rating without those assets? I mean, how hard would that be?

Well, first of all, we don't make that decision. I don't mean to be sharp about that. But that isn't our call. So what we think -- well, we can just speculate but I don't want to speculate on this call.

And that does conclude today's question-and-answer session. Mr. Ziola, I'll go ahead and turn the call over to you for any additional or closing remarks.

Yes. Thank you for joining us, everyone, this morning. Before you hang up, a quick note on our Annual Investor Day, which is normally held in early fall. This year, it will be held on December 3 in New York. A save the date notice will be sent out in the coming weeks. Our quiet period for the first quarter -- for the second quarter starts when we close our books in early July and extends until earnings are released after the market closes on July 30, followed by our conference call at 11:00 a.m. Eastern, 10:00 a.m. Central, on July 31. We'll provide details on the conference call at a later date. T.D. Eureste and I will be available throughout the day to answer your follow-up questions. Thank you for joining us and have a good day.

And this does conclude today's conference. We thank you for your participation.