歐尼克 (OKE) 2003 Q3 法說會逐字稿

Welcome to the ONEOK third-quarter conference call. At this time all participants are in a listen-only mode. Later we will conduct a question and answer session and instructions will follow at that time. (OPERATOR 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.

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 Securities Acts of 1933 and 1934. It is important to note that the actual results could differ materially from those projected in such forward-looking statements. For a discussion of those 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.

Thank you, Weldon, and good morning everyone. I appreciate you joining us today to discuss ONEOK's third-quarter results. Following my remarks Jim Kneale, ONEOK's Chief Financial Officer, will review the financial highlights for the quarter.

To begin, I am pleased to remind you that ONEOK's annual dividend was increased during the quarter by 4 cents per year, to 72 cents. This is the second increase in dividends this year, which have increased by 16 percent. The next dividend payment will be on November 14, to shareholders of record at the close of business today. We have indicated that we will continue to evaluate our dividend policy. We understand the importance of dividends to our shareholders; and we will continue to take steps to ensure that they receive an appropriate level.

As to the quarterly results, obviously we are pleased. We did better than anticipated and had a number of positives during the quarter. Clearly commodity prices helped; but we also benefited by an early result in the rate case in our Kansas Gas Service operation. We entered into a stipulated settlement with the parties that was accepted by the commission and implemented September 20. I am sure you'll recall the settlement amount was $45 million, as compared to the requested $76 million increase. While we felt comfortable with our case, it was a fair settlement and allowed us to forego a protracted proceeding.

As you also know, our Oklahoma distribution operation, Oklahoma Natural Gas, has filed for $24 million in additional revenue. To give you some background, we assumed responsibility for customer service lines in the year 2000. Those costs have been deferred, as has the return. We are requesting the commission to approve our amortizing those costs and receiving the return. We're also seeking to recover costs related to gas and storage for the utility.

The motion for procedures schedule is to be heard this afternoon before an administrative law judge. We have had discussions with the commission staff; and there may be changes to the request, but at this time the outcome of those discussions is still somewhat uncertain. However, we are hopeful to have resolution to these issues before year's end.

Before I turn the call over to Jim Kneale for a financial review, I would like to spend a few moments discussing our recent announcement about the reserve acquisition. You know that we sold about 70 percent of our producing properties in January of this year. At the time, we indicated we could have exited the business; but we chose to retain certain fields and substantially all of the staff in place in order to grow this business back. We also indicated that we wanted to expand our footprint. This transaction accomplishes both of those stated goals.

In addition to 309 proved developed producing wells, we also will acquire seven gathering systems connected to 252 operated wells. These systems have central delivery points that have multiple outlets, with gas currently being sold at approximately Houston Ship Channel, less 10 cents; an improvement over the midcontinent prices we are receiving out of Oklahoma.

The systems handle about 53 million cubic feet per day, of which 26 million will be our own production. The reserves are 91 percent gas and her longlived. These are exactly the type of assets we wanted to acquire. The reserves result from internally generated prospects and have developmental potential. We are very excited about this transaction. I would now like to turn the call over to Jim Kneale for a review of our third-quarter results.

Thank you, David. Yesterday we reported third-quarter earnings per share of 1 cent compared to 17 cents last year. Net income was $4.6 million; and that compared to 20.7 million the year before. Operating income was $31.8 million, compared to $63.8 million last year.

I'm going to cover three items that affect the comparability of the third quarter either to last year's third quarter or the first and second quarters this year. The first item is the recognition of approximately $11 million in revenues related to the handling of a prepayment on a contract, and the re-evaluation of a derivative contract which should have been recorded in the marketing segment in the first and second quarters. These two transactions are a part of the reason our actual results exceeded our third-quarter guidance; however, they have been included in our fiscal year guidance. More importantly, since they swing the marketing segment from a quarterly loss to a profit, we thought it was necessary to explain these items.

The second item has to do with antidilution. In the press release we noted that 17.3 million shares of convertible preferred stock and dividends on preferred stock were excluded from the calculation of diluted earnings per share, due to the shares being antidilutive, which reduced reported EPS by 4 cents a share.

Said another way, to determine our reported EPS, you calculate basic earnings per share, which is net income less preferred dividends divided by average common shares. This results in basic EPS of 1 cent. The normal fully diluted calculation results in EPS of 5 cents. Since that is greater than the basic calculation, we have to report the basic number as fully diluted. The antidilution will not affect the 12-month period; which means the reported EPS for the four quarters will not add to total earnings per share for the year. I will say a little more about that in a few minutes.

Last I want to remind you about the accounting change we implemented in January, which eliminated mark to market accounting on certain energy contracts and put them back on the accrual basis. The most significant change was the elimination of revenues generated from carrying marketing's gas storage inventory at fair market value. As a result, beginning in 2003, revenues will generally be recognized when inventory is sold in the first and fourth quarters, not when the gas is injected into storage in the second and third quarters.

Looking at our year-to-date numbers, earnings per share from continuing operations were $1.49 on income of $152.8 million. That compares to earnings per share of $1 on income of 121 million last year. Operating income for the nine months increased to 326.3 million, or about $42 million over 2002. This increase is a result of better margins in the gathering and processing segment, higher product prices in the production segment, and the addition of our Texas properties in the distribution segment.

Looking at cash flow, we ended the quarter with $12 million in cash, $167 million in short-term borrowings, and had $513 million worth of gas in storage. Our current borrowing rate is 1.15 percent.

Our debt as a percentage of capitalization is about 52 percent utilizing the Moody's methodology for our equity units. This is down about 1 percent from June 30, primarily because of the August transaction where we (technical difficulty) just $50 million or about 2.6 million shares of our common stock from Westar. However, the same transaction improved our cash credit statistics, because our annual dividend requirements were reduced by about $3.9 million.

In the press release, we also revised our previous 2003 guidance of diluted earnings per share from continuing operations upward to a range of 208 to 212, based on our stronger third-quarter results and our view of the fourth quarter. The earnings forecast attachment to the press release is based on $2.10; and we included a breakdown of operating income by segment.

The significant changes to that guidance are in three areas. First, a $60 million increase in gathering and processing, based on improved pricing and our continued success in renegotiating keep-whole contracts. Second is a $13 million decrease in the marketing and trading segment, primarily due to the decrease in regional basis spreads between the Rockies and the midcontinent. Last, a $14 million increase in the distribution segment, due to the implementation of new rates that were approved by the Kansas Corporation Commission that David talked about, and our efforts to control operating cost.

As I pointed out earlier we raised our fiscal year guidance by 5 cents. In doing so, we also revised the fourth-quarter estimate to 61 cents, down from 70 cents, reflecting the stronger third-quarter results, which included some transactions and events that had been forecast in the fourth quarter, and our current view of overall commodity pricing and volatility.

Although I mentioned this earlier, I want to reemphasize the third-quarter antidilution. Reported earnings per share for the four quarters (technical difficulty) will not add to earnings per share for the year. To that point, I looked on First Call earlier this week and noticed that several reported estimates appear to have forced the fourth-quarter earnings per share, so that the four quarters add to the year; which results in some very high fourth-quarter numbers.

We also raised our projected 2003 capital expenditures to a range of 225 to $235 million, to reflect the increased drilling in the production segment. We anticipate 2003 cash flow before changes in working capital will exceed projected dividends of $71 million and capital expenditures by 150 to $180 million.

The last item I want to mention relates to the shareholder agreement between ONEOK and Westar. Once Westar's ownership falls below 10 percent, the shareholder agreement terminates. As a result, the provisions in that agreement that allow Westar to convert series D to common stock in a sale also terminate. From that point forward, the terms of the series D would require Westar to sell the series D in their current form as a preferred security. David, that concludes my remarks.

Once again, to help us respond to questions, I have asked John Gibson, who is responsible for our gathering and processing segment, and our transportation and storage segment; Chris Skoog, President of ONEOK Energy Marketing and Trading; and Lamar Miller, our Senior Vice President, Financial Services, to help respond to your questions. At this time we would be pleased to take your questions.

(OPERATOR INSTRUCTIONS) John Olson.

A couple of questions. First of all, I would love to know about the Black Magic that John Gibson is apparently using in gathering and processing? The numbers are coming in splendidly. What is the mix now, contract mix, between POPs, keep whole, and fee?

I would like to say it is Black Magic. But actually it is the same strategy that we initiated three years ago, which was to renegotiate our unprofitable contracts. That effort continues; and we are starting to see the results of that. It is indicated by an environment where we have shrinking net processing spreads and rising commodity prices; and we are seeing an increase in earnings. All that points to an increase in exposure to percent of proceeds contracts.

To answer your second -- I might also add as far as Black Magic is concerned, the other thing is continued focus on our operating cost. As we continue to operate these assets, we learn how to do them better. We optimize the asset operation.

As far as our contract portfolio, right now we currently sit at 27 percent of our gas under keep-whole contracts; 29 percent under percent of proceeds; and 44 percent under fee-based contracts. As I have mentioned many times before, that number has an ability to fluctuate based on producer elections, primarily behind our Bushton plant. The key thing is we are seeing improved profitability in an environment of shrinking processing spreads.

One other question. That is with the acquisition of the Wagner & Brown properties, are those gathering systems or part of the earnings going to be reported under your part of the business? Or will it all show up in E&P?

No, the gathering systems will fall under our transportation and storage segment.

Transportation and storage, right there. Speaking as to the Wagner & Brown purchase; is most of that production in Cotton Valley so long-lived?

It is all Cotton Valley production; East Texas field.

Having looked at the numbers and the economics, would I be too far out of whack in suggesting that that is accretive to the tune of about 6 or 8 cents a share annually?

Yes; depending on what financing assumptions you put in here, I have run several, and we have not concluded how we are going to finance this in the long run. But one calculation is, with even just 50 percent equity, it would be about 6 cents accretive.

Okay, that is basically what I was looking at on that front. On the marketing side, does Chris Skoog have any better breakdown as to where the earnings came from? From storage or wherever?

John, breaking it down into the buckets in a conceptual way is, the spreads collapsed between the Rockies and the midcontinent, significantly, over a third-quarter of a year ago. But as those collapsed, the spreads between the midcontinent and Waha, the midcontinent and the Gulf Coast, and the Gulf Coast and Chicago all widened back out a little bit. But that was the biggest area of the downward movement in earnings over a third-quarter of a year ago.

The other area was, due to storage, we were busy injecting into storage. Remember we expensed all our storage demand fees on a monthly basis. We don't write up inventory. So we ate almost $15 million worth of storage expenses, because we didn't make sales during the third quarter because of the mild weather. We had nice weather all third quarter. We didn't have any really extreme hot periods all over the country. So we didn't get to turn inventory typically like we like to, with the volatility.

The third-quarter volatility was by far the lowest of the year, of the first three quarters. As you come back in here, into October, the current month we are in right now, volatility is back like it was in the second quarter. As we have seen the NYMEX go from a 460 price up to a 580 price, back down to settle at 440 on Wednesday. So volatility is coming back, it looks like, at this time.

Any early line on 2004 CAPEX yet?

We are in the process as we speak in finalizing our budget for next year. Each of the business units are, as I said, compiling that information. And we will present it to our Board. At this one it would be a little bit premature. But I guess what I would in a general sense say to you is, I would not expect anything much different in terms of CAPEX than what we have had over the last couple years.

Thank you very much.

Yves Siegel, Wachovia Securities.

I have a few for you. One is, Chris, could you give us the buckets that you normally do on your operations?

I can get you pretty close here.

He may have to push some numbers together here, Yves.

I will just move forward. As we talk about the production acquisition, a couple of things. One is, have you been able to hedge any of that production into 2004, number one?

Number two, what are you looking for in terms of -- let me rephrase that. In terms of the proved reserves, how much is developed versus undeveloped?

Number three, related to that, any sense of what CAPEX might be directed towards that business?

Let me cover a couple of those and I will ask Jim to talk about the hedge. Let me give you a breakdown on the categories of the reserves. Fifty-five percent of the reserves are proved developed producing; 13 percent are proved developed not producing; and 32 percent are PUD, proved undeveloped.

In terms of CAPEX, just related to this acquisition, I expect it to be in the 15 to $20 million range for next year.

Does that maintain production or grow production?

It should actually grow production next year. Potentially, the early numbers look like it may be a 13 to 18 percent increase based upon that kind of CAPEX.

Okay.

Michael Heim of AG Edwards.

Hang on just a second, Mike. Let's get back to Jim on the hedges, and then Chris on his buckets.

Yves, in answer to your question on hedging, the answer is yes, somewhat. About a week or two ago, we hedged 15 MMcf a day, 15,000 a day at 518. And we did not set the basis -- and I believe it was 522. I mean total. We have hedged the total. Let me clarify. We have hedged two tranches; it is about 15,000 a day; and it is an average price of 522.

We didn't lock the basis. And that was intentional, because if we were successful in this acquisition, we would look at the basis differential between these properties in a different way than we would midcontinent production.

Mike, are you still there?

Yes I am.

Chris is still putting some numbers together. Let's go ahead and take your question; we will come back and finish his response to Yves' question a little bit later. Thanks for waiting, by the way.

Okay. No problem. Hoping to get a little more color. I don't know if I fully understand the $11 million in revenues that was booked this quarter that should have been in the other quarters. Any more color you can give on that? Why was it not booked? Was there a misinterpretation of things?

Yes, there's two separate items. We mentioned that there was a prepaid contract. We had a customer whose credit was not good, and we started requiring them to make prepayments in February. They actually filed bankruptcy in July. As we were reconciling that -- we were selling gas to them every month, and we have a number of customers that are on a pre-pay status.

But when this one filed bankruptcy we began looking at our exposure to them, and figured out that the accounting folks had not cleared that prepayment off the balance sheet as the gas was sold. We recognized the expense; but we left the revenue money on the balance sheet as a prepayment. So we had to, -- obviously, by the end of the third quarter that completes everything. And that breaks down, about 3 million of that went to the first quarter; and about 4 went to the second quarter.

The other item, it was just a physical index option that ran from July 1 to October 31. When we entered that transaction in June and marked it, we used a wrong price curve for it. As it began settling during the quarter and we began looking at those results, we realized that in one of -- you can imagine hundreds or maybe thousands of different options we have in our system. But again these two, we felt the two were significant enough with our third-quarter results that we needed to mention them.

As you probably are aware, in all of our segments we are always using estimates to close quarters. And we are always truing up estimates. And they kind of wash through the results. But again since these two items really moved the marketing trading from a positive operating income to a negative operating income, we felt like we needed to explain that.

That is helpful. What have you guys said about financing on the acquisition?

Again, in our press release we indicated we had several options. I think my view and David's view is there is a lot of stuff going on out there. Our lockup expires the third. If we knew, when we don't know, what Westar's plans are, we couldn't talk about them. But anything we may or may not do obviously would be factored around if they are in the market, if they are coming to the market. Trying to find the best time if we come to the market.

That said, by March 31, early April, I will probably have -- be back in a positive cash position before this acquisition of about $400 million. So I have the ability to carry it and use cash to pay for it; and/or some combination of equity financing. We will just look at that as we move through the last part of this year and into next year.

There may be some question as to timing. And candidly, obviously, we are going to close the transaction before year's end. But in terms of how we finance this long-term, the final decision has not been made on that. We are going to take a real hard look at the most efficient way, in terms of the balance sheet and otherwise, to finance this acquisition.

Jim, you talked about the cash position a little bit. That is one of things I wanted to hit one. I assume the drop in cash position from the end of June to the end of September is related to the building up the gas in storage. Is that correct?

You're correct.

That is why you talk about 400 million in cash by next spring, as that gas comes out.

That is correct. That gas and other working capital related to putting gas into storage. It is the whole thing. But, yes.

As you know, you would normally use your short-term earnings for that. And in terms of the short-term, we have not used our short-term borrowings to fill storage, in essence. We have used our own earned cash.

Okay. Last question for me, just a confirmation one. On the Oklahoma rate case; this is not a full-blown rate case? This is kind of a one off situation, where you should be able to get a pretty quick decision?

That is a fairly good read. It is not a rate case. And candidly that is why we have had a number of discussions with the staff. It is somewhat unusual; and we do have these issues outstanding; and we are hopeful that the commission will take these issues up and deal with them in a very expeditious fashion. But as I said, we will know more over today and the next week or so, as to where the parties are and the likelihood of that.

Is it designated in a previous rate case that these types of costs should be treated in this manner?

For each of these issues, they are all very different. We have service lines that by order we are deferring the costs. We have, obviously, some increase in cost associated with customer collections that were not anticipated. We have increased gas and storage expense that was not anticipated in the last rate proceeding. So we have a number of those kinds of issues that heretofore some have been dealt with and some haven't.

So it is that kind of mix that is requiring us to deal with the commission and try to find the most expeditious way of dealing with it. Of the 24 million obviously not all of that, because some of those costs were deferred costs, not all that would have a revenue impact. Some of that would just be an amortization of the cost.

But as the commission reviews that request, are they simply doing a prudency review? Or will there be discussions of whether certain costs are appropriate to be recovered in this manner; as opposed to force you to file a rate case if you want recovery?

They will actually do both of those.

Okay, that is helpful. Thank you.

Before we take the next question, let's get a response to Yves' question earlier. I will ask Chris to respond.

The four buckets, in a very crude fashion here, is the trade and transport was about a breakeven area. The storage was down 12 million, due to the fact that we expensed all the gas, as I explained, and we didn't sell much out of the ground. Our retail segment was about 3.6 million. And our power and crude group was about 6.5 million.

Shelby Tucker of Banc of America Securities.

It is Haniksen Groetschke (ph). Couple of questions for Jim. Jim, could you tell us what the impact was of the Kansas rate settlement in the third quarter?

There were two pieces of that. I think in total it was about $3 million. About $600,000 were the actual rate increases; and there was about a little over $2 million of items that, when you began the amortization and truing up the cost to the natural rate order. So again about $3 million total.

At the end of the second quarter, you guys had indicated a third-quarter loss of 20 cents. You have come in at a penny positive. Is there sort of an EPS breakout that you might be able to provide us, to explain how exactly you make up for the 21 cent difference?

I have parts of that. The distribution entities, and more have dollars than -- and I'll try to look at them. The distribution entities were up about 6 cents. The G&P business was up about 7. Marketing and trading was up about 4; if I have all those right.

Okay. On the G&P, I guess it is just improved crack spreads that led to the 7 cents?

Yes, pricing, NGL pricing, gas prices. And some, the volumes and the expense control.

Okay. On the production side for 2004, what sort of natural gas production do you guys expect with the acquisition?

Currently we have about 18 million a day of owned production. And with this addition it should be in the range of 26. So the total would be 44 to 45 range depending upon where drilling comes in.

Okay. Great, that is it. Thanks, guys.

Bob Sullivan of UBS.

Chris, could you outline or indicate how much margin you have realized selling out of the Rockies in the first half of '03? Since you talked about the basis coming in, we could get a sense of the magnitudes that that has benefited you during '03 so far? In other words, the basis was relatively high in the first half of '03.

The first half of '03, the basis was in the $1.50 range. In the third quarter it was in the 60 cent range. If you take that delta times the number of days in the year times my capacity, which is close to 200 million a day, you can back into that number that way, through that chart that we showed. It is on the website. I don't have that math in my head.

That is fine. What are you seeing for '04 in terms of the basis?

It is a fluid market. We are not a market maker, in that we are taking what the market is giving us. But we are hedging off; and current basis next year in the Rockies is trading in the, let's call it mid 70s behind the screen.

You have hedged some of that?

We are in the process of hedging some of that off in calendars '05, '06 and '07.

And '04?

Yes, and '04.

Can you also identify how much on your seasonal gas trades, when you take your gas out of storage during this heating season, what type of margin you have there?

Let's look at two things with you, Bob, if I can. If you look at year-to-date 2002 versus year-to-date 2003, our operating income in marketing and trading is about the same both years. But this year, we are on accrual method; last year we were on the mark method. Right?

So last year I had recognized already at this point $57.5 million of gas coming from storage. And I had recognized almost $15 million in demand charges coming from gas (technical difficulty) from my demand customers over the winter. So I would have collected almost $72 million worth of money a year ago, that I have not collected at all yet this year. Because we are on accrual methodology.

So you can see, we have about the same amount of gas in inventory third-quarter this year; we are at 66.5 Bcf; third-quarter last year we were at 67.9 Bcf. Right now we have locked in an average of just over 75 cents an M. I will not give you what our costs are. But we have locked in 75 cents an M margin on the inventory that is in the ground.

Okay, great.

You need to understand, obviously, Bob, that that spread, that volume is going to be taken out, some in '03 and some in '04, obviously.

Sure. That is helpful. Thanks. The distribution segment looked like it performed a little better than expected. Is that primarily the Kansas rate case? It looks like it was better even beyond just the early increase in the Kansas service territory?

Yes, the rate case was only a portion of it. All three distribution entities have had and continue to have a strong focus on their cost control efficiencies. We focus hard on number of employees per customer -- number of customers per employee and those type of things. We are beginning to see some impact from that.

We also benefited a bit because, with the Texas assets, a part of our forecasting was from historical numbers before we owned it. They are actually performing a little better and costs are a little different; so we picked up some there. So it is really a combination of several factors. But again the Kansas rate case was a part of that.

And you gave how much they Kansas rate case will benefit you for a full year. What is the benefit in the fourth quarter?

I believe our estimate is the rate case impact is about $10 million for the year this year. And so it would be about 7 in the fourth quarter.

On the processing, it looks like your guidance takes into account a decline in the processing operating income in the fourth quarter. Just wondering what you are seeing there? It looks like you have 41 million to date; and 50 million I think is the guidance for the year. So sort of a 9 million fourth quarter?

What we have seen in October is a continuance of what we have seen this year, which is stronger natural gas liquids prices, and stronger gas prices relative to previous years. We have continued to see a shrinking processing spread.

Having said all that, in that environment we will conduct to benefit from our contract restructuring. Having that balance in our portfolio. So I would anticipate that if the market continues as it did in October, that our G&P earnings will see some slight increase over the number that was given.

Okay, great. Thank you.

Gil Gibay (ph), JP Morgan.

All of my questions have been answered.

Devin Geoghegan, Zimmer Lucas.

Just had a couple of quick questions. One, for the ONG rate request, I know you guys asked for 24 million of revenue. In terms of what you have asked for, what does that equate to for net income?

Let me see if I have got that here. If we got everything, it looked like it would be about a $10 million bump to net. But the likelihood of getting everything is not high.

I agree. The second question is, when do guys expect to give '04 guidance? I know your budget is in front of the board like November.

It actually goes before the board in December. So Jim and I have not discussed that. Typically we have waited until our call to give guidance. This is just an off the top of my head reaction; but I think as we get through this process with our Board we very well may, in fact, come out with a release giving guidance for '04. I suspect that would be sometime after the Board has approved the plan for '04.

Not to beat on a dead horse, but the Rockies-Panhandle spread, and then the storage you guys mentioned; is it as simple as us just taking that and I guess annualizing the decrease for next year? I am trying to think of moving parts.

Let me remind you first of a couple things, and I will let Chris supplement this. Gas moves around the United States. It is kind of like a balloon, where you push on one side, it may push out somewhere else. Obviously gas that was moving into California before current expansion was doing so on pipes, obviously from along the southern direction. So if you have the demand increase going to the west out of the Rockies, you're going to see some contraction. But you are going to see expansion somewhere else on other pipes.

So while it is not a zero sum game, you do see those influences. It is dangerous to just kind of mathematically say, here's where it is, and that is what the impact is going to be. Because we move gas in all kinds of different directions. Now that is kind of the 30,000 foot level. I will let Chris address it in more detail.

To clarify something, when I gave Bob Sullivan the formula before, the 200 million a day, about three-quarters of that was hedged this year. Before the basis blew out to $1.50 all the way. So it is hard to tell you the true impact of what was hedged this year versus what is hedged on a go-forward basis. I think we are about 30 percent hedged on '04 right now. In the mid 70 range behind Rockies, behind the NYMEX.

Just to get some sense of moving parts for '03, (inaudible) up to $1.50, were you guys hedged north of a dollar. I am just trying to think of rough changes.

I don't know if I can get you an exact number; but it wasn't nearly as wide as $1.50. We got the benefit on just about 25 percent of our production. I think we were probably closer to the 90 cent range on an average.

That is helpful. Thank you very much.

Mike Werner, Kennedy Capital.

Just to clarify, I was going to ask a question about the '04 guidance as well. But just to clarify it for me, the Board approval of your budget for next year; is that what you are referring to? You said that might take place in December?

We carry our financial plan to the Board in December, and seek approvals of the plan. That is really when we will solidify our projections for '04. That is what we will solidify our expectations in terms of CAPEX and cash flow. It is at that point it would be appropriate for us to come out with some guidance.

Okay. I think that is it, all of my questions were answered, thank you.

Michael Goldenberg of Luminous (ph) .

Just wanted to ask a couple of quick questions. KCC increase of 45 million of revenue and your request of 24 in Oklahoma, what does that mean in terms of ROEs, post the increase in Kansas and the proposed increase?

The first -- let me try to answer that especially even in the Kansas settlement it was a black box settlement so there wasn't an REO set. The same for Oklahoma. These are several items, there hasn't been a rate case for ONG since maybe the early '90s. Again it was black box; so neither one of those have an up to date return on equity.

Then you take that and you say you can impute one. I haven't done the math yet. You can take our capital structure, which, just the way the balance sheet looks, it is 35 percent equity. And I think, these are rough and I haven't confirmed, but Kansas is earning well over 10 percent on our current capital structure. And I think it would put ONG about in that same place if this were successful. But I really have focused on that, that closely, yet.

So we should use 35 percent equity to cap for back of the envelope calculations?

No, I am not suggesting that. I am just saying that is our cap structure for the balance sheet. I think in filings we have made that included a return on equity, we were using more pro forma 50/50 for those operations.

I see. What is the combined rate base of the two entities? Do you have a number for that?

Kansas, I believe Kansas is around $650 million; and I believe ONG is around $550 million.

Okay. Just to follow up on Devin's question about 2004 guidance. So, it is possible that there will be a release before the Q4 call? Or are you planning to do it during the Q4 call?

As I said, Jim and I have not talked about that. Right now off the top of my head, I suspect that we will not wait until the year-end call. That we will in fact issue a release and give guidance before the Q4 call.

Thank you very much.

John Olson of Sanders Morris Harris.

A couple of quick questions if I may. Just in dealing with the contracts in the second quarter, gentlemen, did that create a mark to market income effect? How much mark to market was in the margin, in marketing and trading?

The third-quarter mark to market was about $2 million, really small. Again with the change in all of the accounting we have gone through, I think if you look back last year it was about $22 million just for the third quarter.

Right. That is good to know. Secondly, if I can trouble John Gibson, again. Forgive me I promoted you to John Bishop before, whom I was talking to earlier today.

That is quite all right.

It is Friday, John. If I can ask you, on the third quarter, you've got transportation and storage numbers bouncing all over the place it seems. But they sort of flatten out for the year. Is there any particular reason for that?

Quarter on quarter, the main variance is due to several things. One, in the previous quarter period, we sold some of our Cushing gas out of inventory; so we have a gas sale that is absent in the fourth quarter of this year. We also had some increased fuel cost, just due to the fact that natural gas prices are greater quarter on quarter; as well as our throughput was up a bit.

Operating costs increased quarter to quarter. But that operating cost increase was really attributable mainly to accrual for incentives, benefits for employees, and some outside legal costs or settlement costs. As opposed to operating.

Does Yaggy come under you as well?

Yes, it does.

Is that ever going to come back into operation?

We certainly believe it will. We are working, as I have mentioned before on an operating plan for Yaggy. We do now have the regulatory requirements from the state of Kansas. We are in discussions with the State of Kansas about how we want to proceed with returning Yaggy to service.

Do you have any rough idea of what kind of earnings impact or EBIT impact Yaggy has on an annual basis?

In natural gas service I would say it would range from 3 to $5 million.

That is good to know. Just kind of a general question, if I may. Ethane spreads on gas gathering down here on the Gulf Coast have been positive for only two out of the last 40 months, maybe three. And in the first nine months, they were absolutely chopped liver; about negative $4.50 a barrel. It has created a major whiplash throughout the NGL markets. What kind of price would it take on ethylene to get ethane profitable again?

In this particular month, it is ironic that you mention that. This is our first month, and I'm speaking now of November, that we are going to be in ethane rejection at our plants where we have the capability of doing so. Excuse me, ethane extraction. We have been in ethane rejection this entire year.

What has happened of course is with the drop in gas prices relative to ethane, it is now in our best interest to extract ethane. I do not know off the top of my head what that translates into on a cents per pound basis of ethylene cost. What I do understand, or I have been told, is that the ethylene producers have shown some increased interest in EP mix as opposed to crude derivative feedstock. Which is of course good for the ethane producers.

But getting back to some of that Black Magic you referred to earlier, a lot of our peer companies and competitors have to produce ethane. We have, through operating mode optimization, have where we can limit or not produce ethane when the market doesn't need ethane. So I think that has also helped us throughout 2003.

Thank you.

Yves Siegel of Wachovia Securities.

I just wanted to just make sure I understood all the stuff that went on in the call here. Jim, again, when we look at the utility operations, you have the rate case, Kansas, that was resolved. You also have Oklahoma. In terms of Kansas, I think you said that you expect $10 million to hit this year, 7 million in the fourth quarter. So does that mean that for 2004 we should be looking at something like 17 million of incremental earnings just from Kansas, based on the rate case?

We think the rate case will have about $29.6 million on an annual basis. So yes, if 10 this year, incrementally I would say (multiple speakers) 20. You're going down the right path.

You said potentially the Oklahoma could add another 10 million to that.

Yes, but to be clear, two things. The numbers we are just talking about on Kansas are operating income; so they are pretax. The $10 million David talked about on the ONG filing is net after-tax.

Okay, I got it. To round out Chris's discussion. Chris, has anything changed in your outlook to suggest that that 180 to 230 range for your operations, we should be thinking about any differently?

I think that is a fair range representative of the market conditions that we are looking at right now. I don't see anything that is going to change drastically that is going to take us far off those numbers.

John, with the Black Magic and all that you discussed earlier, is it fair to say that your business should do fairly well into '04, based on the changes that you operationally have done this year, and a little help from the market?

I believe that our continued focus on cost control, as well as optimizing operations, will continue to benefit us. The biggest benefit to the gathering process segment will be rising commodity prices, gas and NGL. Because of the restructuring we have done on our contracts, we will benefit from that environment.

Okay. David, can you just review again on the production side, the acquisition? What attracted you to the Cotton Valley? Was it a negotiated type of transaction? A bid transaction? Just in a market where gas prices were relatively high, I am not sure if that necessarily makes it easy to do these acquisitions and have it be accretive.

Let me kind of take everybody back. We sold these properties, sold properties earlier this year. If you look at the average price that we received back then, and compare that to the average price we are paying today, I think the delta is about 24 to 25 cents in terms of in the ground. In other words, the properties we are buying today are cheaper than the ones we sold earlier this year.

The Cotton Valley has a great reputation. Wagner & Brown has a great reputation for developing prospects. They are an exploration company. We are a producing company. And it is a great fit for us to be in there buying these properties and finishing out the development so to speak.

The transaction, they had a data room, and we went through a bid process. But as is always the case, even though you go through that process, you negotiate to a final transaction. So there was negotiation involved in the transaction.

But we have said for a long time that we believe that there is long-term value in owning and controlling reserves. We still believe that. I can't say enough positive about this transaction. We're really excited about it.

That is great. Finally, Jim, you raised the amount of cash flow that you thank you are going to have this year. What was the rationale or the reason for the increase?

There were two things. A small piece, we raised our guidance for net income; but it more was related to partially deferred taxes in our view. As we get these Texas assets integrated and lives established and run through our tax models, that provides a little more deferred tax this year.

Then the other piece was we had been using a higher estimate for the portion of earnings from marketing and trading that might be related to mark to market, or the non-cash earnings. It appeared we were just using too high an estimate.

You may or may not want to comment on it, but sort of the mosaic of everything that you have spoken about today, is it fair to conclude that for '04 you should be able to have earnings be in that $2 plus type of range?

Sound like to me you're trying to back into some guidance.

I am just being curious. All right, thank you.

Faisel Khan, Credit Suisse First Boston.

(technical difficulty) question. The $11 million in the derivative contract and the prepayment; what was that on an EPS basis? I just want to make sure, that wasn't in the previous guidance, was it?

Let me answer that. First, those two items were in our annual business mix. They were transactions we had, and we knew we had. It is just that when they were realized changed the timing versus for the full year.

The impact of the two on reported was 9 cents. So we reported a penny. If the 11 million had occurred in the first and second quarters, we would have reflected a loss of 8 cents this quarter; but then higher earnings in the first two quarters.

Okay, got it.

This concludes the question and answer session. Mr. Watson, I would to now like to turn the conference back to you.

This concludes ONEOK's third-quarter 2003 conference call. As a reminder, our quiet period for our 2003 year-end earnings will start when we close our books in early January 2004 and extend until earnings are released. We will provide a date and conference call information 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 the conference. You may now disconnect. Goodbye.