歐尼克 (OKE) 2003 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the ONEOK second quarter earnings conference call. (CALLER INSTRUCTIONS) As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Mr. Weldon Watson, Vice President of Investor Relations.

Good morning and welcome. As we begin this morning's conference call, I will remind you that any statements that might include company expectations or predictions should be considered forward-looking statements, and as such are covered by the Safe Harbor provision of the Security Acts of 1933, 1934. It's important to note that the actual results could differ materially from those projected in such forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to the MD&A sections of ONEOK's filings with the Securities and Exchange Commission.

Now, David Kyle, ONEOK's Chairman, President and CEO, will moderate this morning's conference call.

Good morning, everyone, and thanks for joining us today to discuss our second quarter results. I'm pleased report that ONEOK had strong earnings for the second quarter and we've seen improved performance for the organization.

Within the production segment, we've seen an increase in activity and we obviously benefit from higher prices. Gathering and processing continues to focus on adding supply and improving profitability through contract changes. The transportation and storage segment saw improvement and continues to focus on improving margin and throughput. The distribution companies are seeing the effects of the challenging economy, and for them higher prices are not good, as they impact on collectibles.

The Kansas Commission has filed their testimony, and their recommended increase is $28.7 million. You will recall that we have asked for a $76 million increase. We will be filing our rebuttal testimony next week, and as always we're hopeful we can settle with all parties. If not, we expect the Commission to carefully weigh the merits and expect an order in the case by the end of the third quarter.

In the Texas distribution operation we continue to find out opportunities, and after six months of ownership I am extremely pleased with the acquisition and our future.

Finally, our marketing and trading segment continues to perform well, and we continue to see opportunities develop.

The change from marketed-to-market accounting to accrual accounting for certain storage and transportation contracts reduced our operating income for the quarter when compared to the previous quarter, because we no longer carry natural gas inventories at fair value. Instead, these revenues will be recognized when inventories are sold, which is typically in the first and fourth quarters.

We've received many questions about Westar's (ph) intentions with respect to their ownership position. Let me say that the lock up expires next week and they have publicly stated their intention to monetize their stock investment in ONEOK over time. Beyond this, there's not much else I can say. You will recall that they own about 4.7 million shares of common and 21.8 million shares of Series D Convertible into common, and at today's prices should we purchase any of the Series D the premium above the net offering price of $16.52 would be considered a deemed dividend and would impact our earnings calculation. So you can see there's a built-in disincentive for us to repurchase any of the Series D.

All in all, it was a good quarter for us, and I'm pleased with our future prospects. At this time I will turn the call over to Jim Kneale, our Chief Financial Officer, for a review of the financial highlights.

Yesterday we reported second quarter earnings per share from continuing operations of 23 cents, compared to 27 cents last year. Net income from continuing operations was $22.5 million, compared to $32.3 million last year. Operating income was $62 million, and that compared to $79.3 million last year. As David already pointed out, the comparability of the quarters is impacted by the accounting change we implemented in January.

For the six months, earnings per share from continuing operations were $1.66 on net income of $148.2 million. Last year, earnings per share were 87 cents and net income was $141 million. Operating income increased (indiscernible) or almost $74 million over last year, as the result of significant increases in the gathering and processing and marketing and trading segments, and the addition of the Texas properties. Marked-to-market earnings were only $25.2 million.

We ended the quarter with $158 million in cash and no short-term borrowings. Our debt as a percentage of capitalization remains about 51 percent, utilizing Moody's methodology for the equity units.

In the press release, we reaffirmed our previous 2003 guidance of earnings per share in a range of $2.03 to $2.08 from continuing operations, and also included a breakdown of operating income by segment. As you would expect, our mix of earnings between segments moves throughout the year as many factors change. We revised our segment guidance, primarily in the gathering and processing and distribution segments, but total operating income remains unchanged. The increase in gathering and processing is based on our success in renegotiating contracts to mitigate exposure to unfavorable keep-whole (ph) spreads, improved prices and our ability to change plant operations. The decrease in distribution results from higher bad debt expenses, due to higher costs and economic conditions, and increased employee costs.

At this time we still project 2003 capital expenditures to be about $215 million. However, as David mentioned, we are seeing an increase in wells proposed in the production segment, and somewhat higher requirements in the distribution segment coming from the Texas operation that may change that number as the year progresses. Finally, we anticipate 2003 cash flow will exceed capital expenditures and projected dividends by 130 to $150 million.

David, that concludes my remarks.

In addition to Jim I have Chris Skoog and John Gibson joining me today to help answer your questions, so at this point we are now ready for any questions you may have.

(CALLER INSTRUCTIONS)

Kathleen Riftic (ph), WH Reeves (ph).

I was wondering if you could tell me how much marked-to-market income you had in the second quarter of 2002, please, to compare with the 23 million this year.

In the reference to our Q from a year ago, it reflected a significantly more marked-to-market earnings. Keep in mind, as we change the (multiple speakers) accounting, and in last year's Q it was about $52 million, I believe. Keep in mind, the whole -- one of marketing and trading companies (ph), the whole company was on marked-to-market, and let me -- I've got a schedule -- let me -- I'm sorry, let me correct that. Q2 was 66 million. The fiscal year to date was 52 million. But again, the point I'm trying to make is that was when the entire marketing and trading company was on marked-to-market earnings, so they aren't necessarily comparable numbers.

Could you also tell me how you're doing with storage? Have you taken any gas out; where you stand on storage reinjection; and how gas demand for electric generation is going in your region?

That sounds like a good question for Chris.

We're approximately 66 percent full in storage, so we have roughly 46 Bcf of gas in the ground, as it relates to the 70 Bcf of gas we have in storage as of June 30th. And as we released, in the earnings we increased our storage capacity by 5 million cubic feet effective July 31st for the balance of the year, so we are now at 75 billion cubic feet, so the percentages id a little bit lower. As of June 30th we were 66 percent fall. That is about 20 percent lower than a year ago. And we're on pace. We are well ahead of the industry average on their percentage of full, so we're very comfortable there.

With regards to power and the gas usage for this part of the Company at this time of the year, we have run the plant just a handful of days this summer, but that's our strategy, is not to run that plant. Our strategy is to trade around the plant with our heat rate that is not very efficient in the -- what I call the baseball burning (ph) of electric generation. It runs at about a 12-heat rate, as opposed to an 8-heat rate, which is more normally of combined cycles. So the gas to electricity conversion, I would say, it is just like a year ago -- there's no increase, no decrease at this point.

Chris, why don't you address also what you're seeing in terms of your markets that you sell gas to that are power generation?

We have a good increase in the ercot (ph) region for demand from our gas usage. As you see, as our physical numbers have grown drastically over a year ago. And then in the Southwest (indiscernible) in the Entergy (ph) area we've been selling a significant amount of gas to the electric generators. Entergy, Florida Power and Light and TXU were three of our top six customers for the quarter.

Does the answer your question?

Yes it does. Could you also tell me -- I'm sorry to have three questions. Capital expenditures in Texas, is that primarily for upgrading the system? Or are you finding new customer conversions running higher than you expected?

It's actually both. One of the aspects of the way Texas regulation impacts operation is that they have an opportunity in Texas to recover capital investments that are made to relocate pipelines and to change operating conditions by submitting a recovery -- through a recovery mechanism. The downside to recovering that capital is that you don't own a return on it. So one of the things we've looked at as we've operated the system over the last six months is whether or not to go in and seek that recovery. If we seek the recovery, then we will probably be closer to on target with respect to that operation. But if we do not seek the recovery and allow those investments to go into the rate base, then our CapEx may be a little bit higher.

The other area that we're seeing capital is in the area of customer system. We're putting in -- and developing a new customer system that will impact all three of the distribution operations. And one of the first operations that will convert over is the Texas operation. So they are -- with respect to their own individual capital allocation, they are seeing some of that cost this year.

Is that a CIS (ph) system?

It is.

Thank you very much.

Bob Sullivan, UBS.

Sticking on the Texas for a minute, what's the CapEx for Texas and what type of increase are you talking about there?

Jim, do you have those numbers?

Let me first talk about the increase. I think we -- some of the items we've seen -- I think its called KYOGA (ph) is the acronym for this opportunity David is talking about. I think that's only 2, $2.5 million in our projection. The customer information system talking about was an expenditure I think on their would probably be about $3 million, but that's already budgeted at a corporate level. So a net-net increases, that wouldn't have any impact. The original Texas plan -- and I'm not sure and I'm not sure I have that in here with me, so I can't -- I think it was about $18 million.

It was in that ballpark.

Would that come down then by the 3 million once the system is built out?

No. Well, on the go forward basis, for instance, once the customer system was in place, the 3 million would be additive to the 18 this year (multiple speakers) but then it wouldn't repeat in the future years.

Chris, could you talk at all about on the marketing and trading what the profile of earnings opportunities you've seen? Is it more -- and I know they're somewhat linked -- but transportation, trading around your storage, what areas have provided the most opportunity, and what are you looking for for the second half?

The first half of the year was primarily driven around our storage and options strategy. And with the first quarter it was more the spread relationship between the Rockies and the mid Continent. That was very wide. So we've had roughly $157 million of operating income the first half of the year. As you look forward to the balance of the year, we're projecting still being close to that 230 number. As you can see, we're only targeting about $70 million for the second six months. Most of that is due to the fact that our call option strategy book that the decrease in prices over the last seven weeks has diminished a little bit. And with the lower gas prices in here, basis has tightened up between the Rockies and the mid Continent a little bit. So we're still targeting to get to our number, but those two things are going to cause us the second half of the year to be in that $70 million range, not at the $150 million range we were in the first half of the year.

Is there any margin you can talk about that you have already sort of locked in by putting gas in storage and selling it forward?

Yes. We've got a lot of -- all the gas that's in the ground right now is locked in with spreads.

What type of -- sort of is your average spread?

I'd rather not go there. I'm significantly wider than the NYMEX (ph) spread value that you see right there (multiple speakers) first quarter that spread was in the 30 cent range; for the balance of the year this year it is trading in the 65 cent range. We're north of 65 cents, I will say that. I don't want to put us in (multiple speakers) and all that gas is locked in. Most of that is hedged to January of '05 -- I mean '04. (multiple speakers) between December and January is going to be critical to understand whether we get that in the fourth quarter this year or first quarter next year. That's going to be the wild-card and we have figure in ad valorum taxes at year end you have got a lot of different things you need to look at to evaluate that. But all the gas in the ground is hedged.

It's also depends -- let me jump in here -- on customer pools because that is primarily what that gas is used for.

I'm going to follow up with that. Our peaking (ph) business, our big demand dollars we get from the utilities, we're about 70 percent booked for this winter overall, significantly ahead of last year at this time, due to everybody's worried early about whether there is going to be enough gas this winter, are we going to get to the 3 tcf (ph) level nationally. So the LDCs have come out earlier this year than a year ago. So we're about 70 percent of the way there. We have less than 300 million a day of peaking capacity available to us. As you know, our model, we sell two-thirds of our total deliverability. We're within 300 million today of that level already and we're not even into the first day of August.

Can you provide some assumptions on the processing business for the remainder of the year in terms of maybe liquids prices, gas prices, that you're assuming? Or what type of -- if you want to put it in terms of a spread.

What we've seen just over the last two or three weeks is gas soften while crudes remain strong. There's every indication that propane inventories are floating (ph) in the Gulf Coast area, primarily through imports, but remain below five-year averages in the mid Continent. So our view is still not going to be any demand or market for ethane to speak of, but propane and heaviers ought to be strong in the mid Continent relative to natural gas for the balance of the year. Our spreads through the first half -- probably 50 percent of last year. I think they will strengthen somewhat in the second half, but probably not get back to last year's spreads.

A couple more questions. The interest rate swaps, when were those put on again?

I think the swaps were put on towards the end of 2001.

And do you still expected new rates in Kansas to be in effect this year?

Yes. We should have an order out by the end of the third quarter.

One last question -- you mentioned the impact for buying back the Series D, I guess. Is there any tax impact to that or is that just sort of a reported earnings impact?

There's no tax impact to speak of. It's a reported earnings issue that the SEC specifically has provided guidance on companies that repurchase preferred stock. If you buy it for more than its book value, you report it as a deemed dividend, which, as you know, impacts your calculation of earnings per share. We had that same issue with the Series A we repurchased, but because of that -- remember our old D95 (ph) and participating dividend, the additional earnings that were allocated to the Series A holders over the life of the (technical difficulty) were used as an offset to the deemed dividend. So it only impacts us about $3 million in January. But on a go forward basis, obviously the D doesn't have the same characteristic. So it changes that landscape considerably.

One last question. I am sorry. On the deferred income taxes, you continue to benefit there. What's the outlook for that? How long will you continue to sort of generate cash for income taxes?

Looking out, this year it's kind of -- it's kind of difficult to find the true impact of deferred income taxes because we have the sale of the properties and those taxes are reported net. If you look at the cash flow statements for the first six months, deferred income taxes were about $68 million. That's down from last year's of about -- I think it was 106, I believe. But last year's included, you get different things going on. Last year included the impacts of us taking some NOLs back two or three years, and then some additional property. So all of that said, it's -- my estimate for this year is deferred income taxes will be 70 to $90 million, and looking out a year or two I still believe they're going to be in the $70 to $80 million range.

Michael Garvey (ph), Angela Gordon.

The swaps -- what are the remaining terms there? When to they expire?

You are talking about the interest rate --

Interest rate swaps, yes.

We have swaps on really four different Series of debt. One of them -- well, really three (indiscernible) now. One is 20.28 and the other two are 20.11. So the swaps, if we leave them in place, could run that long. We monthly watch where interest rates are going, what they appear to be doing, and there are different things to look at to determine when you may or may not exit those swaps. But with our swap rate is about 85 basis points over LIBOR. So we have quite a ways to go for LIBOR to move before we start approaching that breakeven point.

Chris, you commented about how quickly you looked up your peaking supply for the winter. Has there been any change in premium with the concern over the supply situation?

Yes. We've experienced probably -- it's been coming down here over the last couple of weeks from the premiums that we got earlier this year, but we're probably as much as 50 percent higher over a year ago, to probably a more realistic average of the average of the whole book is probably in the 30 percent higher than a year ago.

We are probably not going to say much more beyond that because we still negotiate with customers and don't want be disadvantaged.

No, I'm just trying to get a ballpark qualitative type of response to that. You still have some left. And even with the CapEx coming up a little -- potentially coming up a little -- it still leaves you a bit of free cash. What are your plans on that side?

As you know, since you have follow this company and watched this company for several years, we are an acquisitive company and we're still looking at opportunities to grow. And candidly, it's a good position to be in, to have that free cash flow as we look at those opportunities. If none of those develop, we still have the opportunity to pay down debt going forward. So beyond that, I think that's really all that we can say at this point. But those are really the opportunities for us.

One last question. On the additional drilling, could you give a little more detail as to what you're pursuing there -- ballpark costs and production additions, reserve additions?

What we're seeing -- and I really can't get into too much specific -- but what we're seeing in the fields that we have retained from our disposition back in January is because of the higher prices that producers saw we've had a lot of wells proposed on us. In other words, these are non-operated wells, and so when the wells get proposed you really don't have much control over the timing. And you either can participate or go non-consent. And so from our standpoint, we've got a -- we kept those fields for a reason. And that reason was the upside potential. So as those things have come in, we've chosen to participate. So we've seen an increase just from those retained fields.

Any dollar ballpark on where that CapEx is now and where it may go?

It's probably low double-digit addition to where we had expected it to be, so almost a double.

Yves Siegel (ph), Wachovia Securities.

In the past you have given a breakdown of the composition of your operating contributions. Do you have that available?

I'm looking for it here. The second quarter?

Yes.

About of the 30 -- I'm trying to come up with -- of the total of $30 million, approximately a little over 20 million of that came from the marketing and transport segment; about $3 million came from the storage segment. Obviously we're spending time filling storage during the second quarter. We're not selling a whole lot of out of storage. That's why the number is way down. Our retail book was around 4 million. Our (indiscernible) businesses was around 1 million, and the mark, as we referred to earlier, was 13.3 million.

Okay. Thank you.

Take away you're operating expenses (inaudible) --

I assuming that operating expenses are pretty stable from quarter-to-quarter?

Yes, we're actually $1 million below budget, but we're $8.8 million for the quarter.

If I could just move to -- Jim, could you -- it seems to me that you raised your free cash flow estimate from the first quarter. Is that just on the deferred tax line or is there something else going on?

The deferred tax line primarily, and less estimate of a little less mark earnings, and then some really small other things here and there.

Thank you. And David, could you just comment on what your thought on dividend policy going forward, given the new tax legislation?

Clearly the President and the Congress have provided an incentive, and I guess I would add also a benefit, to stocks like ours. We, as always, monitor our payout ratio against a peer group. We do that each and every time the Board meets and considers a dividend. I do expect that we will consider at the appropriate time before year-end what our dividend payout should be, and I'm sure the Board will take it into consideration. But I can't really say at this point whether it will increase or not. Certainly, the President and the Congress provided an incentive for us to do so.

The last question is, any update on the idle storage capacity that you have?

You're talking about within Chris's operation or in John's?

In John's.

Owned storage.

Yes.

We're still in the midst of our studies in Texas and we're still awaiting final determination on the regulations in Kansas. They put the rules out, but then they are reconsidering those and they are still not published.

Can I push it with one more question? Any thoughts on filing any addition cases (ph)?

Let me take these in terms of jurisdictions. In Kansas we have a case pending. Oklahoma, we always -- we look at each of these operations, and I think we're taking a look at Oklahoma currently. We've not made a decision to file, but clearly we think there are opportunities for us to come in and potentially seek relief in Oklahoma. But that decision has not been made. But it is something we're looking at. With respect to the Texas operations, that's a home rule state and as such each of the jurisdictions in which we operate are self-determininant (ph) and periodically we will be filing cases in Texas, but they will not be headline in grabbing type cases. Typically they are smaller in terms of the requested amount that they are very diversified in terms of their timing.

Derick Cribbs (ph), Glenview Capital.

On the marketing and trading -- on the natural gas liquids side, how much of the business is now keep-whole (ph) versus percentage of proceeds?

When you look at our total revenue stream, currently right now 27 percent of total revenue is keep-whole.

How does that compare as to a year ago?

To a year ago significantly reduced -- quarter -- I think I have the information on the quarter. Quarter it was -- actually I don't have that information.

Just approximately, a guess.

Probably -- I am guessing two or three percent. What's different is that on our keep-whole contracts we have some keep-whole contracts that are profitable when the spread is wide. We also -- so what we have done is gone in those particular contracts and renegotiated those terms such that when the spread turns negative, the customer -- the producer in this case -- pays us a fee to process the gas. And the fee is not a breakeven fee; it's a fee that is at market conditions, it is allows us to make a return and it allows the producer to get their gas effectively markable so it can be taken to market.

Secondly, the Westar (ph) preferred that they own, can they sell that as a preferred? Can they sell it at common? What kind of rules are there regarding that?

Jim can correct me if I get off track, but they can sell it as a Series D preferred -- carry the preferred dividend -- or they can convert and sell it at common. So it's really -- they can go either way with that decision.

Chris Edmonds (ph), Prichard Capital.

I will follow on Derick's question about the Westar. They filed and received approval from the KCC to engage in private transactions. And, Jim or David, I'm wondering what the limitation of selling the preferred, in terms of holding percentages and the like, might be on a private transaction and what kind of veto power you might have if indeed they did try to sell some of that privately?

Let me ask Jim help me on that one.

There's a provision in the shareholder agreement that allows Westar to sell less than five percent without our approval. But there are other conditions related to that. They can sell -- the starting point is, is at under five percent of the common interest with the shares of the deed being contemplated to be sold, converted to common. And then there's another catch to it -- they cannot sell more than -- there's a limiter (ph). If the person they're selling to own more than five percent, Westar cannot sell to the holder so that at the end of the transaction that holder would own more than 9.9 percent. And that was designed to prevent a PUCA situation.

So the bottom line is, it's a 10 percent limit in the aggregate.

Those are automatic restrictions, not restrictions -- the five percent restriction, for example, is an automatic restriction, not a restriction that they have to come to you for approval?

They can sell five percent or less to somebody without our approval.

Fantastic. Let me move to the storage issue. I know you said you have added in the quarter about five Bcf of lease capacity, it looks like. I'm curious as to whether or not that is adding bulk in existing storage regions, or if that's some sort of additional geographic diversification to the storage profile.

That's a good question. We're going to -- Bcf for that is in new facilities, primarily in the Upper Midwest and Chicago-Michigan area. As we it continue to exploit and expand our position geographically and as we are inching our way ever so closely to getting into Canada, we been talking about the last 18 months or so, we're getting ready to deploy that. And we're focusing on getting our storage up there. Storage in the field zone (ph) is (indiscernible) something in the market -- storage in the market zone is worth something greater than X due to the increased volatility as you get farther away from Louisiana. So we're focusing on if you deploy the same capital dollars to inject into storage, basically you can get increased volatility, why not go to a new area up in the market area and that's what we've been focusing on.

David, you may have addressed this with Bob's question earlier, and I think I may have missed. I know you file your rebuttal testimony in the Kansas rate case on August 4th. Can you walk me through after that, the timeline you see and when you see attempting to wrap the rate case up in Kansas?

The timeline as I recall, Chris, as you said, we will file our rebuttal. They will take that under consideration. There are hearings scheduled, and I think they are from mid to late August. And then of the commission will take it under advisement and do their deliberations. Intermixed in that whole process will be ongoing discussions with the staff and the interveners. And as I mentioned in my opening comments, we're always hopeful to be able to negotiate a settlement with all the parties. I think we mentioned in our release the level of requests that the interveners, in terms of a range, that they have filed. As I said, we're hopeful that we can negotiate a settlement, which will be going on throughout that time period. But the hearings are scheduled for, as I said, mid August and quarter order out (ph) by the end of the third quarter.

One final question related to the exploration and production business -- there's a lot of -- there's a lot of transactional activity occurring in the mid Continent, which is right down your fairway. I'm curious as to if you can provide any color on the looks you're getting, and if there are things there that might be of interest as we go forward, and if that continues to be a focus.

Clearly what we saw, or what we've seen, over the course of the year with the higher prices showing up in the first and second quarter, there were a lot of packages that came to market. And candidly, we've had an opportunity because of our ownership position and just being recognized in the industry we've had an opportunity to look at many of those packages. Obviously producers' expectations and what prices look like at a time drove their decision to put those packages out. That also translates into an expectation of what they would receive. We've looked at a number of the packages and will continue to do so. But I should note that while we look at the mid Continent and Texas properties potentially, we also are looking North and West. So beyond that that's really all I can say. I don't want to get into any specific packages that we've looked at. But we are clearly a player in the process.

Devin Gohagan (ph), Zimmer Lucas.

One, I was curious -- a lot of LDCs that I've been following have had a drain on cash this quarter to put gas in the ground, and you guys seem to get away with a quarter with no increase in short-term debt. And cash only dropping 150, which I assume is largely associated with the gas in the ground for EM&T (ph). How did you guys manage through this quarter, just at the LDC level?

I think the way to start to look at that is, how do we come out of the first quarter in terms of cash position. And I will let Jim address that.

We did end the quarter with $158 million. If I remember correctly, at the end of the first quarter we were closer to $300 million in cash. And then if you -- I guess a component we have not talked about a lot, maybe this will answer your question -- the LDCs put some gas in the ground, and I believe they have -- the combined three of them have about 25 Bcf of storage. And they have about 19 to 20 Bcf in the ground right now. So although it does work -- pull on my working capital somewhat, it's not that big of an outlay, especially when you look at the amount of storage Chris has. That said my projection is we will go into a net borrowing position sometime this month; and again, expect to be out by mid-November. And part of the reason is we came into the quarter with a lot of cash, but with the free cash flow I am generating, it's helping me cover these ebbs and flows in the working capital because of the gas in storage.

The second question, not to harp on the West Star preferred, but I just want to clarify -- let's say they do sell a third of their position in common stock, and they do a secondary. Would you guys help out with the roadshow, so would that be the plan for the combined companies, or would they just do it on their own.

When we contemplated and negotiated deal back in January with those folks, we did in fact agree to assist them in their marketing effort as part of that agreement. So the answer to your question is yes, we would.

They're not restricted from doing a third of it as long it's to different entities that don't own more than 9.9 percent. Is that right -- they could do the whole thing if they wanted to. They could do the whole thing if they wanted to, but no more than 5 percent to a single holder.

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Yves Siegel.

Can you discuss the seasonality in earnings now? The dip in the third quarter, is that primarily because of more exposure on the gas utilities side, as well as going from marked-to-market to accrual?

The short answer is yes, but there's always a but -- or except but. Yes, the utilities historically lose money in the third quarter, and I think you can go back and look the third quarter Q a year ago they lost money. The biggest change it is that now, with this change in accounting, since we won't to be marking storage injections to market in the third quarter, those earnings won't recur. And so when you pull those earnings out, it puts us potentially in a breakeven to a loss for the third quarter position.

Then it gets a little more complicated because of the preferred dividend, and we have to look at what's called the basic earnings per share calculation, which means you take your net income, less preferred dividends and divide it by the common shares. So if that produces a lower EPS than a fully diluted calculation, you can't disclose fully diluted. And that in fact is what happens, and will probably happen in our third quarter this year.

Now you get to the end of the year, that calculation goes away and you take the earnings for the year and divide it by the fully diluted shares and you get fully diluted earnings. So it's just a quarter anomaly for us.

The result is that you just can't take the reported quarterly numbers and add them together.

If I could just move to the other question on the gathering and processing side, I'm just curious if there are more contracts that you're working on to renegotiate? And the flipside too is by renegotiating the contracts, do you limit the upside because a couple of years ago I think you did over $100 million in this segment?

We are still in the process of renegotiating contracts. We are in the midst of negotiations right now with two of our largest producers in our Kansas region. We renegotiating with several of our producers in the Texas panhandle.

The comment about the upside, you do somewhat limit the upside, if you do believe that you're going to extremely large keep-hold spreads. But our point of view on pricing is that gas remains strong. NGLs also strong, but the days of 1 to $2 gas and $25 crude creating a huge spread are probably not going to happen that often. So it's in our best interest to change our contract portfolio to reflect that point of view.

One of the added benefits of moving our keep-whole exposure to a percent of proceeds is that -- remember on a keep-whole contract we stand 100 percent of the costs of the energy consumed to convert that MNBTU (ph) gas to liquids. On a percent of proceeds, or percent of liquids, we share the costs with the producers. We get an added benefit of helping to reduce our operating costs by moving more towards these sharing agreements.

The other thing I would add to what John has said is and point out that he talked earlier about adding this language to these keep-whole agreements when the spread narrows and turns negative. That has the benefit of providing some stability to that contract from the downside, but it still preserves that upside opportunity for us. So while in fact our longer-term view is that the spread is narrow, and as such we ought to move away from keep-whole, we still have the prospect of those type of contracts providing some upside if it does in fact blow out.

I think as we've agreed, we will keep some percent in our portfolio keep-whole, just properly structured to protect our downside.

That's a great explanation. I appreciate it. I just have one other question for Chris. Chris, going forward what's your thought on terms of market volatility? Do you think -- and also basis differential? Do you think that, given that the market has moved down a bit here that the environment has changed? Or would you continue to look for a fairly volatile market going forward?

As it relates to volatility to start with, it has decreased over the last several weeks with this lower movement in natural gas prices. As you and I have talked about before, as that lowers the winter-summer spread value increases. So the perception of lower prices -- remember the spread at the first quarter here, the winter-summer spread was 30 cents; volatility was running around 60 percent. As of today, volatility is running about 46 percent. But your winter-summer spread has gone through 35 cents out to close to 65 cents. So your intraday (ph) volatility -- changing subjects on another one -- your intraday (ph) volatility is still there. It's still like it had been in the second half. The first quarter it was very wide with the severe weather. During this time of year volatility is still there in intraday market. It's just not as significant -- as people just -- they don't have to withdraw from storage; they can defer their injections, so there is still ample gas out there, so you would have volatility a little bit, but not like you do during the wintertime.

With the lower prices (indiscernible) basis will continue to tighten in with respect to spreads in the Rockies and those type issues. Just as natural prices get lower everybody tightens up their belt a little bit and they're willing to accept -- not willing to except the lower price so they bring the basis market in.

Does that answer your question?

Yes, and I guess I would argue that perhaps in the fourth quarter if gas prices rise seasonally, then that would just reverse in terms of the basis differential. Is that correct?

That's correct.

Bob Sullivan, UBS.

On the new storage that you signed -- you guys have obviously done very well with your strategy -- have you seen any change in cost to lease the storage?

Yes. As we did our renewals this year, some were down a couple of cents; some were up a couple of cents, depending on really the geographical location and the demand for them. The production zone storage typically trades cheaper than the market zone. As we've gone out and signed this year about 6 Bcf in total of market zone storage, we're paying more for that storage than what we turned back last year. Remember last year we had 80 Bcf at this time. We turned back 10 Bcf. Most all of that was in the production zone. So in a roundabout way our storage costs are lower than a year ago, but on a field-by-field basis we're paying a little bit more because we change -- redeployed our strategy to the market zone. But the renewals that we have done in the field were basically flat from a year ago.

Looking forward how should we look at these renewals? How much storage comes up every year for -- that you look to renew?

I am going to go off the top of my head here and I'm going to -- part of this I'm going to wing, but it's about 20 Bcf comes up in 2004, about 40 Bcf goes to 2005 and there's about 10 Bcf that goes out through for 2008. So it's staggered pretty well, that we don't have all our eggs in one basket and one year we are sitting and negotiating 80 million or 70 Bcf worth.

I have no further questions. Please continue.

This concludes ONEOK's second quarter 2003 conference call. As a reminder, our quite period (ph) for our third quarter 2003 earnings will start when we close our books, will be some time (technical difficulty) and extend until the release of our third quarter earnings. We will provide a date for that release and conference call later.

This is Weldon Watson, and I will be available throughout the day for follow-up questions concerning today's conference call. You may call me at 918-588-7158. On behalf of ONEOK, thank you for joining us and good day.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may disconnect at this time and have a great day.

(CONFERENCE CALL CONCLUDED)