Exhibit 99.1
(Genesys Conference Call)
(Confirmation Number: 2971675)
(Date: February 27, 2003)
(Time: 10:00 a.m. EST)
(Header: Oneok)
(Host: Weldon Watson)
(Length of Call: 60:00)
OPERATOR: Good day, ladies and gentlemen and welcome to the ONEOK 2002 earnings conference call. At this time all participants are in a listen-only mode. Later, we’ll conduct a question and answer session. If you have a question at that time, please press the one on your touchtone telephone. If you’re on a handheld set pick up the handset. This call is being recorded. I’d like to introduce your host for the conference Mr. Weldon Watson, Vice President of Investor Relations.
WELDON WATSON, VICE PRESIDENT OF INVESTOR RELATIONS, ONEOK: Good morning and welcome. As we begin this morning’s conference call. I’ll remind you 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’s important to note the actual results could differ materially from those projected in such forward-looking statements. For a discussion of factors that could cause the results to differ please refer to the SEC filings. Also fourth quarter income statement numbers will be available on our web site later this morning with the 2002 year-end earnings release.
And now David Kyle, Oneok’s President and CEO will moderate this morning’s call.
DAVID KYLE, PRESIDENT AND CEO, ONEOK: Thank you, Weldon. Good morning everyone. I appreciate each of you joining us today to discuss our fiscal year 2002 results. I’m extremely proud that our earnings for 2002 increased by 64 percent over 2001. I’m also proud that we were able to achieve those results during a year of challenge and accomplishment for Oneok.
Let me review for you some of the significant events since our last conference call. Consistent with our strategy of divesting noncore assets, we sold three gas processing plants and an interest in a fourth plant all in Oklahoma for $92 million in December 2002. Then in January our production segment sold $300 million in reserves. We kept about 28 percent of our reserve base and will continue our strategy of acquiring and developing reserves in this segment.
Both of these sales generated needed capital to fund our acquisition of Texas distribution properties for $420 million. Closed on January 1, 2003 and renamed Texas Gas Service, these properties deliver gas to about 535,000 customers in Texas. The combined effect of these actions has reduced our risk profile and added stability to earnings.
At the end of January, we filed for a $76 million rate increase in our Kansas gas service division. We acquired these properties in 1997 and they have not had an increase in rates since 1996. The 15 percent increase requested is in large part due to the increase in rate base as we’ve invested about $50 million per year in pipe and facilities and have seen an increase in costs. The commission has 240 days to review and act on our request.
Beginning with discussions with the new management at Westar in late November and early December, we were able to enter into a new shareholder agreement that provides us needed flexibility while affording us the necessary protections. At the same time, we replaced their Series A security with a Series D preferred security with division security rights and a fixed dividend. The fixed dividend eliminates a special calculation on reported earnings per share required by D-95.
We also had agreed to repurchase up to $250 million of their convertible securities using proceeds from two equity offerings in January. Because of the success in raising additional capital from both of those offerings and through mutual agreement, we repurchased an additional $50 million of their convertible securities. The result of all of this reduced their ownership position from about 44.4 percent to about 27.4 percent on a fully diluted basis.
In January, we met with many of you as we visited 14 cities and held 42 meetings in a seven day equity road show. Our efforts resulted in the issuance of 13.8 million of new common stock and issuance of 16.1 million corporate equity
units. Together these two equity offerings produced cash proceeds of $618 million. I’m also very pleased that we have added to our investor base and we’ve been able to share our story with many new and potential shareholders. 2002 was a very eventful and busy year and has set the stage for what we anticipate will be another successful year in 2003.
At this time I would like to turn the call over to Jim Kneale, our Chief Financial Officer, to review the financial highlights for 2002. Jim
JIM KNEALE, CHIEF FINANCIAL OFFICER, ONEOK: Thank you, David. Good morning to everybody. As we reported yesterday, earnings per share for 2002 were $1.39 compared to 85 cents in 2001. On a fully diluted basis, excluding the impact of D-95, earnings per share were $1.66 per share. Cash flow from operations before changes in working capital was $461 million, an increase of $33 million over last year. The increase is due primarily to the higher net income and deferred taxes.
Cash flow after working capital changes was $812 million, a $407 million increase. Capital expenditures were $232.5 million, and that compares to $341.6 million last year. Cash flow from operations, excluding the changes in working capital, exceeded capital expenditures and dividends by $176 million.
Interest expense declined from $140.2 million in 2001 to $106.4 million in 2002, due to savings of about $20 million from our interest rate swaps and the impact of less short-term debt from the higher cash flow and lower short-term rates. Operating income, including the operating income for the production properties that were sold in 2003 that will be reported as discontinued operations, increased to $389 million or about $93.8 million over last year.
Marketing and trading operating income was $181.5 million, compared to $74.8 million last year. Our increased storage capacity, higher winter/summer spreads and volatility in natural gas prices resulted in margins increasing to 13 cents an MCF from 10 cents last year. We also began trading crude oil and natural gas liquids in this segment and that added about $12 million. 2002 also includes $10 million related to the recovery of a portion of the Enron charge of $37.4 million that was recorded in 2001.
Gathering and processing operating income declined to $33.1 million from $43.6 million last year. Although NGL sales volumes increased 25 percent, composite NGL prices decreased 17 percent. Prices received for natural gas also decreased from $4.16 to $3 per MBTU. Additional facilities being leased increased customer charge offs and higher employee costs, and a $2.4 million charge related to assets that were sold increased operating costs.
Transportation and storage segment operating income was $53.3 million, flat with 2001. Net operating revenues increased slightly, but were offset by higher operating costs from legal expenses and bad debt.
Distribution operating income increased $33.9 million, to $95.2 million. Due to a settlement with the Oklahoma Corporation Commission, 2002 includes the $14 million reversal of a portion of the $34.6 million charge that ONG recorded in 2001. Taking out this impact on 2002 and 2001, net revenues were slightly down. Operating expenses and depreciation increased $11 million over last year, primarily due to higher employee costs and more assets in service.
The production segment’s operating income, including both continuing and discontinued operations, was $27.8 million, compared to $57.9 million last year. This decrease was primarily the result of lower natural gas prices.
Other income of $12.4 million includes $7.6 million gain from the sale of our Magnum Hunter Investment and $3.4 million related to the sale of some storage rights and transportation pipe. Other expense of $19 million, primarily includes $10.1 million in legal fees and settlement costs related to the terminated Southwest acquisition.
David has already mentioned our recently completed production sale, financings and the Westar repurchase. I want to take a few minutes to talk about a couple of impacts from these. First, as of today, based on the equity units receiving 75 percent equity treatment as Moody’s has confirmed to us, we are approximately 51 percent debt and 49 percent equity as compared to 65 percent debt at December 31st, 2001. These calculations include short-term debt. Today we are in an $80 million net cash investment position and project that at the end of the first quarter we will have $250 million to $275 million of cash invested.
David also mentioned that D-95 accounting for our earnings per share calculation is eliminated as of February. And last,fully diluted shares should decrease by about 4.3 million shares to 96.4 million for 2003. The final topic I want
to cover is EITF 02-03, the rescission of mark-to-market accounting for certain energy contracts. As most of you know, the rescission is effective January 1st, 2003. We will record a charge after tax in the first quarter to implement this accounting change and that’s the easy part.
On our recent financing road show, we had not yet been able to determine the amount of the charge for a number of reasons. Most importantly, there was limited guidance from the FASB and the Big Four accounting firms were trying to reach consensus. Although there’s been some clarity, there’s still some cloudiness. However, with that in mind, we reference the fair value table in our third quarter 10-Q on the road show. The model transaction line reflected a value of $166 million, which was based on a snapshot of market conditions on September 30th and includes most of the contracts that will be impacted. Not included in the model line is another $15 million for a total of $181 million at September 30th.
The $181 million has two components. The fair value of the physical energy contracts of $195 million, and the fair value of the related derivatives of a loss of $14 million, net to $181 million. The rescission applies only to the fiscal energy contracts and not the derivatives. So at September 30th, the charge would have been $195 million pretax. At December 31st, the fair value table will reflect $204 million of model transactions and there’s still another $15 million in other parts of the chart. Although some of the transactions in the September 30th number had been settled, market prices changed dramatically from September 30th to December 31st.
The total fair value of the energy contracts increased to $231 million and the fair value of the derivatives loss decreased to $12 million. The $231 million fair value of energy contracts will be an after tax charge of about $141 million and has three main components. On a pretax basis, the physical gas storage value is $85 million. The transportation value is $56.7 million. And the out of market contract purchase price reserve is $96.2 million.
Each component will be recognized in operating income over a period of time. The storage value, $85 million, will be recognized primarily in the first quarter of this year. Assuming no change in prices in the prices used as of the January 1st valuation, the transportation value will be recognized over the next several years, $36.8 million in 2003, $9.9 million in 2004, and the remainder in small increments through 2018.
The out of market contract purchase reserve recognition will be $23.5 million in 2003, $19.5 million in 2004 through 2006, and $13.7 million in 2007. In total, 63 percent will be recognized in 2003 operating income and 76 percent by the end of 2004. That said, it’s important that you remember that the calculation of the recognition of the transportation contracts, primarily, is based on prices on January 1st. And those prices will not remain static over the recognition period. I suspect that this probably has generated a lot of questions and we’ll be glad to discuss those shortly.
David, that concludes my remarks
KYLE: Thanks, Jim. Before we get into questions, many have asked about our earnings guidance for 2003. Remember, as Jim mentioned, January earnings are calculated under D-95 while the balance of ‘03 is not. We currently expect 2003 earnings to be in a range of $2.20 to $2.30 per share of common stock. You should note that this includes the gain on the sale of our reserves, but obviously does not include the impact from the one time charge of $231 million, represented as the rescission of 98-10 or 02-03.
Before I open the call to questions I mentioned to John Gibson who is over the Transportation and Storage, Chris Skoog leading the Energy Marketing and Trading, and Lamar Miller, Risk Control Officer, I’ve asked them to assist me in answering questions. At this time I would open the call to questions you may have.
OPERATOR: If you have a question press the one. If you would like to be removed press the pound key. If you have a speaker phone please lift the handset prior to pressing the one key. One moment for questions.
The first question is from Daniel Neumann, Banc of America Securities.
DANIEL NEUMANN, BANC OF AMERICA SECURITIES: Good morning. I have two questions related to the distribution business. First, is there any lag on the recovery with the higher gas costs? And second, can you describe how you have reserved for bad debt expense and perhaps compare your current reserves to the reserve levels you had in place during the last significant gas price spike about two years ago? Thanks.
KNEALE: This is Jim. First, on the bad debts, our practice is to create an allowance for bad debt equal to a percentage of the sales revenue. So as gas prices go up, that allowance will also increase with the increase in bad debts – is I guess how I’ll put it. What we saw two years ago when we had the long periods of high gas prices, we saw both an increase in the dollar amounts from normal bad debt customers and we also had other customers who couldn’t pay at the prices. So we kind of use a formula that steps up that accrual. With that said, both ONG and Kansas Gas Service have taken steps to lock in prices on some or all of their gas supply. So the increases that we’re seeing are going to be in some cases substantially mitigated as with the final gas cost gets passed through. And remind me what your first question was.
NEUMANN: It was the lag on the recovery.
KNEALE: OK. Gas cost typically is just on about a 60 day lag from occurrence to billing. We had what we believe to be an unusual situation several years ago when the commission entered that order that caused us to write off part of the gas cost. We don’t anticipate that happening. There’s been a lot of work with the commission going, both commissions, going forward in that area. So typically it’s just 60 days.
I might also mention, we now have the Texas assets and they work the same way. I just mentioned ONG and KGS. But they adjust their allowance for bad debts as we see different factors impacting that. So at the end of the day, we expect there may be a slight increase in bad debts. But hopefully with the steps we took to mitigate gas costs that will be minimized.
NEUMANN: OK. Thank you very much.
OPERATOR: Your next question is from Donato Eassey from Royal Research.
DONATO EASSEY, ROYAL RESEARCH: Good morning. Congratulations on changing the earnings mix. I think you may have touched on this a little bit earlier, but I was wondering if you could be a little bit more specific about the asset earning mix that you have today and how much of it has moved from the gathering and processing side over to the LDC side, which obviously reduced that risk profile you were talking about. And the other, if you could cover a little bit, your earnings are moving up significantly from the traditional levels that you’ve had in the past, this $2.20 to $2.30 level. But the EITF, it seems that you all are handling it a little bit differently than others in spreading the charge over a longer period of time. I was wondering what the rationale and if you could explain why? A lot of people are taking it in the first or second quarter of this year, but not necessarily spreading it out over time. Thank you.
KYLE: Let me start off and say that there is obviously a lot of confusion and Jim walked through an explanation of the EITF 98-10 or 02-03. The $231 million charge will hit in the first quarter. The breakout that he gave was to give some indication as to when we sort of expect those marked revenues to actually turn to cash, what would be cash generated earnings. So the spread on the book reserves, that goes out over time, because that was set up on the books when we acquired the contracts from Kinder Morgan in the Kinder Morgan acquisition. And as such, that represents out of market value of those contracts and it will amortize over the length of those contracts. The storage value comes back, as Jim said, in essence, the first quarter. And the transport value of the majority of it comes back through this calendar year. So to be clear, the $231 million charge will in fact hit in the first quarter. Jim, why don’t you take the balance of the question or add anything you need to that.
KNEALE: That’s accurate on the charge. I would add, on the earnings mix, this year about, ‘02, about 40 percent – 41 percent of our earnings were from regulated operations. That’s our distribution and transportation and storage. Looking forward to the mix of earnings with selling the three processing plants, the production properties and then acquiring the properties from Southern Union, that should, of course, obviously depend on how prices work out. That should put us close to 50 percent regulated, 50 percent non-regulated earnings mix, just somewhat of a snapshot in time. But that’s going to be pretty close. It moved it about 10 percent towards the regulated side.
EASSEY: Thank you very much and good luck with this new mix.
OPERATOR: Our next question is from Mike Heim, AG Edwards.
MIKE HEIM, AG EDWARDS: Good morning. How are you guys?
KYLE: Fine. How are you?
HEIM: Fine, thanks. I want to make sure I’ve got an understanding of this guidance correctly. Let me run through things and make sure we’re clear. You said $2.20 to $2.30, including the gain on the sale of the E&P properties but excluding the charge, correct?
KYLE: That’s correct.
HEIM: And the gain on the E&P properties was somewhere around the $65 million to $70 million or about 40 cents a share, something like that?
KYLE: I think it ended up being $75 million pretax.
HEIM: So, if we exclude that we’re talking about numbers more in the $1.75 to $1.85 type of range. But now let me ask you this. We have the charge coming up and then we’ll have essentially kind of a reversal of that charge as those items come through, correct?
KYLE: Correct.
HEIM: Did you say 63 percent of what would be charged would be recognized in ‘03?
KYLE: Yes, Mike, that’s accurate.
HEIM: So that equates out of that, I guess I calculate it at $1.38 or so of charge on the $231 number. I know $231 is based on January 1st and can change. But 63 percent of that is about 85 cents or something like that. If we don’t include the reversal of that charge, does that mean we’re talking about earnings of only about $1?
KYLE: If you don’t include the charge?
HEIM: The reversal of the charge.
KYLE: I’m trying to follow you all the way through.
HEIM: OK. It seems to me unfair to exclude the charge but then not exclude the reversal of the charge, as the cash comes in the door.
KYLE: The reversal was included.
HEIM: The reversal was included?
KYLE: Yes, Let me be clear. The $2.20 to $2.30, all that excludes is the one time charge. As we look forward in terms of our business and we understand that we’re going to – I talked about the storage and Jim talked about the storage aspect and the recovery of the book reserves, those are all embedded in that $2.20 to $2.30 number.
HEIM: Yes. If we were to take that reversal out, we’d be talking a lower number. And if 63 percent of the charge gets reversed in ‘03, that’s 63 percent reflects somewhere around 85 cents or something like that.
KNEALE: Yes, Mike, let me see if I can help. The $2.30 again includes the estimate of the portion of – I mean it includes the reversal. But one of the impacts you also have to consider, moving off of mark-to-market accounting. If you fast forward to next fall, typically when we injected the 80 Bcf under mark-to-market accounting, we would recognize the full value of that storage season in the second and third quarter of ‘03.
Now that we’re not going to mark those storage contracts to market, we’ll pick up the November and December portion of that, but the January, February and March portion, which typically would be in ‘03 will now be in ‘04 under the accrual method. So what we’re doing is we’re truing up mark-to-market accounting and we’ll clean up the ‘02 – ‘03 season with this reversal, but then areas we would have booked under mark-to-market for later in the year won’t come in. So all of that to say, prices had a tremendous impact on this business. The $2.30 includes the estimated reversal. But you can’t take that whole 60 percent and say, well, that does or doesn’t totally impact the mark-to-market earnings. And that’s the difficulty. You have to identify molecules that go with it.
HEIM: Yes. Well, we’re clearly struggling with how to talk about earnings given what’s a large charge that would normally be taken out but the fact it does reverse and helps out earnings as the cash comes in the door in later quarters and maybe later years. And I guess that’s what I’m struggling with. And maybe why don’t we take this off line a little bit and later and talk about it. Let me get to some other questions. First, can you finalize what the earnings would have been if we had not had the funky dilution, the D-95 accounting?
KNEALE: $1.66.
HEIM: What were earnings for the quarter, by the way?
KNEALE: Thirty three cents on D-95.
HEIM: OK. And as I kind of back out the operating divisions, if I’m doing things right, it looks like flat or rising results for most divisions but marketing was down a little bit. Am I right in that? Can you talk about why this December quarter’s marketing results were a little bit below last December quarters?
KNEALE: Chris is here shaking his head. So I’ll toss this one to him and let him talk about it.
HEIM: Shaking his head yes or no?
CHRIS SKOOG: Mike, fourth quarter, 2001, with impact of mark-to-market last year in 2001, we lost $11.6 million in the fourth quarter, because remember we take all our gas out of storage. It all turned to cash. Fourth quarter of 2002 we made $17 million. We had a $28 million positive impact for fourth quarter comparison, quarter to quarter.
HEIM: I must be doing my numbers wrong.
KYLE: Fourth quarter 2001 also had the Enron charge.
HEIM: OK. I think I might have subtracted that out of the $11 million.
KNEALE: Mike, this is Jim. Just as a, a couple points, operating income, quarter to quarter, $87 million for ‘02, $12 million for ‘01. The EPS was 33 cents. It was a loss of a nickel a year ago.
HEIM: Since we have Chris on the line, Chris, can you make any comments about what happens to your group when we go through some of what we’ve seen with gas prices this last week? Is that the type of stuff you’re able to capitalize on or not?
SKOOG: Yes. Mike, as you’ve been following us for eight years. Our strategy of trading around this 80 Bcf of storage, volatility is what we like. If you go back to the winter of 2000 and you’ve been following us that long, we got hurt in a sustained period of 90 straight days of cold weather but this month the weather has been coming in waves, we’ve been cycling the storage facilities. Without getting into too much detail, because it will jeopardize some things we have within the family, we were at 83 percent in inventory levels going into the middle of January. So we have an ample amount of gas in storage. We have 66 BCF of storage in the ground through January, so this cold weather over the last week hasn’t hurt us.
HEIM: How did you know gas prices were going to go up, you kept storage that high?
SKOOG: You look at supply and demand and look at the national storage levels and we felt hoarding storage would be to our advantage. The weather in Oklahoma hasn’t sustained high periods of demand. That’s where most of our storage is located.
HEIM: Did that change how you look at your normal injection withdrawal type periods, especially looking at what the futures curve looks like?
SKOOG: Yes.
HEIM: Does that mean are you more likely to be taking gas out of storage even for a later period, then? Into the
summer?
SKOOG: I wouldn’t believe I’d go that far. Where February traded and where February cash is trading where March NYMEX settles, you can’t afford to take the opportunity to pass up $9 gas in March for $6 gas in the summer. So we’ll probably be working on emptying the storage facilities like we have been over this past week and over the course of March. We ought to be pretty close to empty. That’s our goal. Now, whether the weather holds in and the prices hold, that presents an opportunity.
HEIM: OK. Great, I think that answers my questions and I’ll talk to you about the earnings issue a little bit off line later.
OPERATOR: Our next question is from Bob Sullivan, UBS Warburg.
BOB SULLIVAN, UBS WARBURG: Just a quick question following up with that. Your 66 of your 80 still in storage?
SKOOG: No, that was as of the first week in January.
SULLIVAN: First week of January. Is there an updated figure there?
SKOOG: I will say we’ve been withdrawing significantly over the past 10 days.
SULLIVAN: You withdraw capacity what per day?
SKOOG: One point six – at this time a year we’re down off our peak day. Our peak day withdrawal is 2.3 BCF. Storage deliverability declines as we decline in the curves. So I will say in the 1.6, to 1.8 BCF per day range over the last week.
SULLIVAN: How would we look at the earnings impact of that coming out of storage with these prices, or have you locked in prices for pulling that out already?
SKOOG: There’s two components to that. There’s the demand. There’s the first month physical call business. Remember we talk about that. We sell about 60 percent of our deliverability from storage on a first of the month call basis. We keep about 20 percent of our total deliverability back for freeze offs and keep about 20 percent to make hay in the open market.
SULLIVAN: OK.
SKOOG: So we haven’t been experiencing significant freeze offs yet in this cold front. It’s not sustained for a long period. When you get 48 to 72 hours of cold weather in the Oklahoma – Kansas area with high liquids in the gas you experience a lot more freeze offs and fortunately the weather is breaking out here and we’re not sustaining a significant amount of freeze offs at this point.
SULLIVAN: When you said you’re going to pull $85 million back into earnings after the charge off, in the first quarter did you say?
SKOOG: Yes.
SULLIVAN: Is that primarily related to this high gas in storage and you plan on pulling that out and selling it at the futures prices that you’ve locked in is that the $85 million?
LAMAR MILLER: Bob, this is Lamar. That is a pretty good snapshot of what that would be.
SULLIVAN: OK. And then just on your earnings guidance, could you provide a little bit more specifics in terms of the segments what you’re maybe looking for on an operating income basis for ‘03?
KNEALE: This is Jim. At this time I don’t think we want to go down that path. It’s so early in the year, the way these prices are moving. At this time, I would rather not do that.
SULLIVAN: Maybe if you could talk a little bit about on the processing side, what you’re seeing there with the price movement and some of the things you’ve been able to do to maybe offset the upswing in gas prices here?
JOHN GIBSON: This is John. February is a different story than March. In February most of our gas purchased at first of the month index. So what we’re doing during this rise in natural gas prices is basically move as much shrink volume as we can into natural gas and sell it into a rising natural gas market. So it really helps or benefits us in February. But when we go into March, it appears that we’re going to have first of the month prices around say $8.50 here in the mid content. That’s going to result in a negative processing margin, but even more importantly it impacts our fuel.
Our shrink volume of say, you’re talking about round numbers, 100,000 MMBTU a day if you’re upside down on your margin, you do the math, you’ve got exposure to that negative margin. But if your fuel is, say, 15,000 or 20,000 MMBTU a day you’re paying $8.50 for it, that’s the big hit. When we move into March we’re optimizing our operations to do a couple things. We’re minimizing shrink volumes and selling as much as we can as natural gas. And the second thing is we’re looking for every opportunity to reduce fuel consumption.
SULLIVAN: What are you seeing for liquids prices right now? Where are liquids prices right now?
KYLE: Liquids prices, absent natural gas, are pretty darn strong. We’re seeing about 50, 52 ethane and 88 cents propane. There’s apparently developing shortfall in propane but there is not alot of propane or ethane being produced in the mid continent. Most of the peer companies are in the same mode we are. Before long the market will see or feel the effects of reduction in ethane and propane production.
SULLIVAN: One final question. The quarter over quarter decline, fourth quarter to fourth quarter, in the distribution segment, could you just provide some details on, looks like that the fourth quarter came in below the run rate of the last couple of few years?
KNEALE: This is Jim. A year ago we were, of course we were 6 million. The charge we recorded which was about $34 million. So that would be about $40 million. We were about $30 million. I think it’s two things. Weather was a lot warmer in the fourth quarter of this year compared to last year. Depreciation expense is higher, as we continue to, especially in Kansas, as we’ve continued to invest money and not get returns on those. So that’s one of the key components of this rate case is to get that entity earning what we believe is a fair return. It’s primarily, I believe, again, weather related and I say that because it was warmer, you’d think with weather normalization, but the way the weather normalization mechanism works in Kansas, if it’s real warm it actually takes a little earnings away from their margins and we saw that happening late this year ‘02.
SULLIVAN: I understand the other segments are more difficult. But could you give some type of guidance on the operating income from the distribution segment in ‘03?
KYLE: Not at this time. No. We’ve provided information before that reflected we expect of course to add the Texas assets and I believe we indicated that should add about, I don’t have it in here, but about $40 million of operating income on an annual basis.
SULLIVAN: OK. Thank you.
OPERATOR: Our next question is from Kathleen Vuchetich of Reaves.
KATHLEEN VUCHETICH, REAVES: I was wondering if you were planning on buying any more shares from Westar in ‘03 or ‘04?
KYLE: Candidly, we have not factored any of that into our mix. Obviously that’s something that on a go forward we will evaluate. But none of that is reflected in any of the numbers that we’ve shared.
VUCHETICH: OK. And could you all comment a little bit with gas prices so much higher, do you have plans for how you’re going to reinject storage? Are you going to follow a pretty normal seasonal pattern? Are you going to time it more? How much discretion do you have on reinjection of gases with storage?
KYLE: I assume you’re asking with respect to the marketing efforts. Obviously the utilities will follow their practices
as prudent distributors should. But, Chris, you want to talk about your plan?
SKOOG: The easiest way to look at it I can completely fill my storage caverns in roughly 96 days, I have 225 days over the summer to play with those 96 days. So it’s going to be the opportunity presents themselves.
VUCHETICH: You do have a lot of discretion, then?
SKOOG: Yes, the front half of this curve at I think April was trading $7.25 or 30 cents when I walked in here this morning. You’re not going to put a lot of $7 gas in the ground to sell next year at $5. Looks like our cash flow should be positive for the first half of the summer as we get started to fill storage. Later in the summer if the market presents itself opportunities to inject earlier, but we have a lot of discretion.
VUCHETICH: Thank you. A final question for Jim. Jim, as you go forward in ‘04, is the base of earnings that you want to grow from the $1.80 to $1.90 number excluding the gain on the sale of the E&P properties, is that with accrual earnings going forward, is that the kind of base you’d look to grow from?
KNEALE: Let me make sure I understood your question. You’re asking me if the $1.80 guidance, I don’t know where the $1.80 came from. I guess you’re saying the $1.66 times 10 percent, is that …
VUCHETICH: No, I’m thinking, more the guidance this year of $2.20 to $2.30, less the gain on the E&P properties comes out somewhere in the $1.80 to $1.90 or so. That you’ll do accrual earnings going forward. Is that the base of earnings you all expect to grow from?
KNEALE: Without having some other information in here, I think I could answer yes to that. What we’ve talked about and I’ll address the gain a little bit, is that over time that we will grow an average of 10 percent. And we really instituted that policy in, I mean as a target for us, in 2000. And then if you roll those earnings forward, and the way we look at it is if you begin in 2000 and grew those at 10 percent compound every year out to time, that over time, we would deliver earnings per share cumulative of that amount of money.
Although I understand what you’re asking for projecting ‘04, I guess our view of even the gain on the resources properties is that is a fast forward of future years income and so the way we view this, it’s the total earnings delivered to our shareholders over a period of time. So we consider that part of our delivery of 10 percent growth. Now, again, that said, obviously we have to fill that hole going forward, which we believe we probably have done with the acquisition of the Texas properties.
I hope I didn’t muddy the water, but yes, we intend to continue over time, growing at 10 percent. Then the caveat I would add to that is, as you know, as our 10 percent target has been perceived by some as high. But we believe in this environment there are opportunities that we can achieve that, in two years or three years or four years, as we get bigger and the landscape changes, that 10 percent target may be more realistic at seven or eight. But I can’t look that far out into the future.
VUCHETICH: Thanks so much, guys.
OPERATOR: Our next question is from Michael Garvey of Angelo Gordon.
MICHAEL GARVEY, ANGELO GORDON: Good morning. I wanted to go back to the EPS issue and the EITF 02-03, I want to be clear on this. The charges you’re booking were previously all recorded earnings that were recorded as mark-to-market, correct in prior periods, like ‘02 and earlier?
KYLE: Yes.
GARVEY: So you’re basically, just to adjust to accrual you’re reversing out earnings that were recorded earlier and then you’re just moving on to an accrual. Like the 63 percent being recognized this year, under the old method, that would have had no income statement impact but all the cash flow would have come in, correct?
KYLE: Yes.
GARVEY: When you go through and review with your auditors, I mean going forward, the accrual method, this would be normal earnings.
KYLE: That’s correct, yes.
GARVEY: The way your auditors are telling people is basically you would record your recurring earnings as whatever the accrual numbers would be?
KYLE: Yes.
GARVEY: Because I come up somewhere in the $1.70 to $1.85 adjusted for the gain, taking out the gain on the Chesapeake properties. But that’s assuming you’re going to pick that up, factoring in the amount that you’ll book on accrual earnings. When you look at that, do you see any significant – I mean you commented on the impact over the year. Could you just like walk through how the impact, if you looked at prior years mark-to-market versus current year, any timing issues you would come up with and kind of order of magnitude on that front.
MILLER: I’ll try to tackle that for you. Let’s clear up some part of the first comment as far as is this just a mark-to-market. It’s the mark-to-market on the physical side of the book only. Not the derivative side of the book. So that’s the first starting piece. So yes, there would be some incremental impact into these different years as those values are thrown into the deal. As Jim mentioned, when there’s a snapshot at 1-1, so to go out there and say what that impact will be a little out in front of the, of course outside the fence, per se, because we do not know what gas prices will be. Like this quarter you saw where gas prices went could be more effect or less effect depending on what happens.
The other question as far as the accounting firm and what potentially could turn around, the biggest piece that came in, Jim talked about was the transportation and contract reserves. Under mark-to-market accounting, most of that reserve would just be repriced on a quarterly basis and we basically had to step back to what the reserve would have been at the time we picked the assets up, amortize it out to the time that the rescission happened, one and whatever balance is left there we had to reinstate. To me that would be the most significant timing difference in the mark-to-market to accrual adjustment. If that makes sense to you.
GARVEY: What about when you looked at the, over the window, when you inject your storage and pull it out? In a typical year, the bulk of that would probably be – I guess this is kind of a Chris question. Is the bulk of that more January/February oriented in terms of how you’re pulling data or is it just too dependent on whether a pricing to really give an idea how that would shake out over the five withdrawal months?
SKOOG: It’s a combination of those Mike. We sell the demand service over the five winter months. If it doesn’t materialize in November and December, it’s sold in January and February which is the pinnacle of the winter season. Last year, if you remember a year ago, we never got below 39 BCF in the ground because the winter of ‘01, spring of ‘02, the weather never materialized last winter and gas prices went to $2. There was no sense pulling $2 gas out of the ground during that period of time. We left almost 40 BCF of gas in the ground during the winter. With it trading in the $8.59 range, it behooves us not to drain the storage facility – to drain the storage facility.
GARVEY: Each year, the potential is there could be a lot of variability year to year in terms of the schedule and how much you leave. So there could be some timing shifts there?
SKOOG: Yes. But on a go forward basis, you ought to see, remember the last three years we’d have big second and third quarter mark income and first and fourth quarter cash income. On a going forward basis we won’t have that mark income in the second quarter and third quarter it will be the more traditional accounting when we pull the gas out of the ground, we’ll recognize the income.
GARVEY: Potentially I guess this could make your earnings a little more seasonal, is that a fair statement? Towards the winter quarters?
KNEALE: That’s right. Yes. Let me answer that. But then the one item that we’re still and everyone else in our situation is wrestling with is we keep talking about the derivatives side of these contracts wasn’t included in the rescission. So you have the derivative side of the transaction that is subject to market fluctuations and what we are reviewing is, can you qualify those under FAS 133 and account for those as hedges? But, your answer is right. The storage, physical flow, the earnings will now match the cash on that.
GARVEY: OK. Thank you very much.
OPERATOR: Our next question is from Craig Shere, Standard and Poor’s.
CRAIG SHERE, STANDARD AND POOR’S: Seems like you all are producing a lot of cash. I think you all said you had $812 million of cash flow, $176 million of operating cash flow before working capital and excess of CapEx and dividends; is that right?
KNEALE: That’s correct.
SHERE: You’re projecting $250 million to $275 million cash on hand at the end of this quarter?
KNEALE: Yes.
SHERE: What do you want to do with all that cash?
KNEALE: Well, I have several alternatives. I think I would answer – obviously there are several things we can do. And David might want to address this issue. We have stated that we continue to look at opportunities in various aspects of our business. And I think David might elaborate on that. We also have, if we continue to generate that cash, we have a couple series of long-term debt issues that one is callable right now. It’s about $100 million. There’s another one callable in October that is about 6.5 percent debt that we’re not going to invest cash at 1.4, you have to look at that pretty hard. But David with that …
KYLE: I think I would just echo what Jim has said. This company is an inquisitive company and we look for opportunities. Clearly there are a number of folks who are taking the advantage today to or I guess in some cases need to raise capital through selling of assets and we in fact do look at a number of those asset packages. And so we do that on a continuing basis. So obviously we very well may have a need for the cash if any of those should develop. But we also have the alternative to address debt as Jim mentioned. So we will, as I said, just continue to evaluate those opportunities as we go forward.
SHERE: Just to summarize, I mean prior questioner inquired about any prospects for reducing the Westar overhang. So you would, no order. Look at new investment to the degree that a good opportunity exists. Then debt reduction, then reducing the Westar overhang?
KYLE: I think that’s fair.
SHERE: Couple of other quick questions. Are you planning on keeping your pension assumed return on pension assets of 9.85 percent and do you have any projections for absolute or year-over-year changes in contribution to the pension income statement?
KNEALE: A couple of those issues. I think we’ve just been through – couple months ago now we went through a revaluation as we do annually of our pension plan funding and we’ve dropped the return on assets from 9.8 percent down to 9 percent . Again that’s a long-term look. And then we dropped the discount rate, I believe, to 6.875 percent, I believe. I can’t remember the number exactly. So we dropped both of those. The impact of that is we had I believe about a $18 million pension credit this year and –
SHERE: ‘02, you mean?
KNEALE: ‘02.
SHERE: That’s pretax?
KNEALE: I think that may have been $24 million. I’ve got someone giving me a number. With all of our different pensions and benefit plans, it might have been about $24 million. I’ll have to clarify that for you. But the point is that this new result dropped at that point, the credit by about 50 percent, I think, to about $13 million. So we’re still over funded. Of course as the market continues to go down, that’s a point in time view. But at the moment we’re over funded.
SHERE: So you’re expecting $13 million pretax credit in ‘03?
KNEALE: Excuse me?
SHERE: You expect a $13 million pretax impact from the pension in income on the income statement?
KNEALE: That’s correct.
SHERE: And it was 24 – 18 for ‘02?
KNEALE: Yes in that range. I think the 24 is a combination of all of our different pension plans and may even include our medical plans, too. But, yes. It’s about in that range. And I think the new discount rate is 6.8, not 6.875.
SHERE: You have managed yourselves quite well and have a great opportunity with gas prices and your storage levels where they are. Would you characterize your EPS guidance as fully reflecting the potential of this or more conservatively optimistic?
KYLE: I guess I’ll start with this and I’ll let Jim answer to it. I think it’s conservatively optimistic, Jim anything to add?
KNEALE: I would add, when we obviously put our plans together for this year, they were based on prices we were seeing late December, early January. And we continued to look at that and the impact of those. And I think some of the conversations you’ve heard from how they impact marketing to potentially how they may impact the G&P business adds a realm around that. But I would tend to agree with David. Our projections used a more conservative pricing environment than we have seen so far especially the last 30 days.
SHERE: Great. Thanks for the help.
OPERATOR: Our next question is from Mike Werner, Kennedy Capital.
MIKE WERNER, KENNEDY CAPITAL: I just have a couple of follow-ups. I know there’s been a little confusion over your earnings guidance again. I just wanted to, for my perspective, because I don’t know the story as well as some others on the call. Can you tell me how you benefit when gas prices are at higher levels?
KYLE: Just generally and then I’ll let Chris add to this. From a 30,000 foot level, if you look at our strategy with respect to gas marketing, and I can take this from a couple of areas. Before I get into gas marketing, let’s say distribution, Jim has already addressed that. We believe and have confidence that we’ve fairly insulated distribution customers both in Kansas and in Oklahoma from these dramatic increases. So, on a distribution segment side, we don’t see much impact from this increase. John Gibson addressed the impacts from the gas processing side. Obviously higher prices impact that. But they also have the opportunity to sell those liquids, those entrained liquids in the gas stream. That can mitigate some of the downside impacts.
Now, when you look at gas marketing. It’s 30,000 foot level, as you go into this last recent period with gas in the ground, in essence in a naturally long position, then you obviously have the opportunity to capture some of that value. And as we’ve told many folks, our strategy is to trade around our assets. And the challenge is to capture that volatility that occurs in natural gas pricing, using those assets. So when you see gas prices rise dramatically, the intuitive view is that that’s going to be a very positive thing for the marketing effort. So Chris, do you have anything you want to add to that?
SKOOG: Yes, David. I just want to clarify one thing. We are not speculating on gas prices. Our gas in storage is always hedged to the first of the month index. Once you get in the month, on the day-to-day basis we can accelerate or decelerate our pulls from storage based on today’s pricing. So for example over the last couple of days gas prices have been $10 and higher. We can sell gas into that market today and buy the April contract at $6 and capture that $4 margin without taking inherent risk. I just want to make sure everybody understands that. We’re not price speculating. Our gas in storage is hedged the first of the month index. Then once the month starts we can day-to-day arbitrage the opportunities as they present themselves.
KYLE: Does that help?
WERNER: It does. To go it one step further, in prior years you were marking to market and because of EITF you’re going to be on an accrual basis?
KNEALE: We still have the financial side. If you put gas in the ground and incur that physical cost, then you can also hedge those costs with a financial derivative. And so what EITF 02-03 did was it said you can no longer include in your mark changes in that physical value. But you still, we still are required to mark the financial side. And so we will continue to have mark-to-market impacts from the financial side of the equation.
WERNER: And what this charge is, that $230 million charge or whatever, is backing out the prior mark-to-market and then you’ll be recognizing going forward the accrual of those mark-to-market; is that correct, in some sense?
KNEALE: The physical side of it.
WERNER: OK. Thanks very much for clarification.
OPERATOR: Our next question is from Devin Geoghegan, Luminous Management.
DEVIN GEOGHEGAN, LUMINOUS MANAGEMENT: Great year. Just wanted to ask a couple things about your contracts and what not. Are you seeing customers asking to firm those up, out a couple years given the volatility that you’re seeing now? I know some of those customers contracts have maybe been shorter term. Are you seeing a firming up of that in the long term?
KNEALE: I’ll take that. The demand for this first of the month call business that we sell with the marketing and trading we have a lot of interest from our existing customers and several new customers are calling already wanting us to renew business for next winter already. With the demise of the large big energy merchants, those people providing these services, the list is getting shorter. So they’re trying to get positioned for next winter, especially what’s happened over the last 30 days. So, yes, we’re experiencing an increase in interest in our service.
GEOGHEGAN: Is it fair to assume, because I hear a lot of people focusing on sort of the earnings, the optical earnings this shift and that shift seems like the cash flow in the business hasn’t changed and in fact it seems like you guys are creating an increasing cash flow stream. Is that the right way to view your business?
KNEALE: That’s exactly the right way to look at it.
GEOGHEGAN: In terms of the accrual shift, had it not been mixed, I realize it’s kind of moot, because I think what I’m missing and I think some other people are missing sort of what the current accrual would be in for, you wouldn’t be recognizing that this year had you not shifted. Is that in line or better than what in the past happened? Does that make sense.
KYLE: Let me see if I’m understanding your question. Is your question sort of if EITF 02-03 did not happen, what would we be seeing those numbers for ‘03?
GEOGHEGAN: Right. Because I think the disconnect, because this one shift is happening this year, is we’re used to seeing what you would be paying in ‘04, under the current system we’re seeing that mark-to-market. But to get a better feel sort of like what ‘04 is looking like so people, at least I can get more comfortable ongoing stream, I think that’s what’s being, I think people are missing that.
KYLE: If I understand the question correctly and I’ll let Jim correct me if I get off here. But if you assume that EITF 02-03 did not happen and where we think we would have come in on the year, I think the number would be in the $1.80 to $1.85 range.
GEOGHEGAN: Realistically it’s actually hurt you guys a little bit? I mean it’s kind of – at least it’s in line with what the current guidance is. On an ongoing basis this $1.80 is what we should be looking at?
KYLE: I think I said $1.80, $1.85.
GEOGHEGAN: I’m sorry. That’s right. Sounds great you mentioned you’d be in $200, $275 cash investing position. Just to understand that I remember on the road show you thought you’d be able to pay down all short-term debt by the end
of the first quarter and be in a cash position. Is that sort of the execution of that?
KYLE: That’s correct.
GEOGHEGAN: Thanks so much, guys.
OPERATOR: Next question is from Derek Cribbs, Glenview Capital.
DEREK CRIBBS, GLENVIEW CAPITAL: First of all, I want to apologize to you and everyone else on the call because I think I’m going to ask the same questions again. But obviously, there’s still confusion, because I think that your guidance is very positive and I think that people are still a little confused. So, if it’s OK, I’d like to go through it again?
KYLE: I appreciate the effort. In fact, all these efforts on the part of these FASB and EITF are to clear up confusion. And unfortunately, my impression is it’s creating more confusion. So, any clarity would be helped.
CRIBBS: If I could start at the beginning you made a $1.39 in ‘02 but if you take out the change from getting rid of the preferred stock you actually made a $1.66 in ‘02.
KYLE: That’s correct.
CRIBBS: Second of all, your guidance is for $2.20 to $2.30 in ‘03 but there’s a $75 million gain in there.
KYLE: Correct.
CRIBBS: If we tax adjust that and use the shares outstanding, I get a $1.70 to a $1.80 after taking out that gain. Am I in the ballpark there?
KYLE: I think that’s right.
CRIBBS: Now, that $1.70 to $1.80, the difference from that, from the $1.66, is that number one, you’re taking out any mark-to-market earnings that you would have made this year, had the accounting not changed. And you’re adding in the accrual earnings from the mark-to-market that you had earned in the past.
KNEALE: This is Jim. Yes, I would agree with that.
CRIBBS: I think the last gentleman or before asked this question, but I want to ask it again, which is if we had not made
the accounting change you actually think that the mark - -to-market earnings this year would have been higher than the accrual earnings. So actually it hurts you a little bit and instead of making a $1.70 to a $1.80, you think it would have been a $1.80 to a $1.90?
KNEALE: I know I said $1.80 to $1.85.
CRIBBS: I’m sorry, $1.80 to $1.85.
KNEALE: I’m not sure I’m following the sequence of what you’re saying there.
CRIBBS: All I’m saying we got to a $1.70 to $1.80 using accrual this year. If you did not have to switch to accrual this year and instead of recognized accrual earnings went back to recognizing mark-to-market earnings, it would have been a little bit higher than that for ‘03.
MILLER: This is Lamar. On that, that would depend on what type storage contracts we entered into and transportation contracts we entered into and rolled over. If there were the same length as previous contracts, we would have been, I would think, pretty close to the range that David has given you with this additional volatility in the market in this first quarter you might have seen an increase in the first or second quarter that might have been captured by the end of the year. But I haven’t thought about that because we’re switching to accrual and I’m not going to be able to roll in a two-year contract. Maybe we roll from one year and took a two-year extension on it.
CRIBBS: Because I think what’s really the confusion is that is that everyone is worried you’re recognizing earnings that you already earned in the past and you’re taking a charge and just recognizing the same earnings again. But really all you’re doing is replacing mark-to-market earnings that you would have earned this year with accrual earnings.
MILLER: That is a good analogy. And with those accrual earnings that we would earn that base control earnings there’s potential to earn incremental earnings above that due to this change.
CRIBBS: My last question is the $1.70 to $1.80 is a fair number to use going forward from which to apply your 10 percent over time. I realize it’s not 10 percent in any one year but is that a fair number, the $1.70 to $1.80 to apply over time 10 percent earnings growth?
MILLER: I would say so.
CRIBBS: I’m sorry everybody. Thank you for your time.
OPERATOR: Next question is from Craig Lucas, Lucas Partners.
CRAIG LUCAS, ZIMMER LUCAS PARTNERS: Good morning. I don’t want to actually beat up that bush anymore. Seems like it’s been thoroughly beaten up in terms of EITF. I have a couple of very specific questions regarding the EITF. The number of years that essentially are represented in the $230 million, do you know what that is? In terms of the life of the asset or the contract, I mean, I’m sorry, of the asset that was the physical asset that was shifted over to accrual from mark-to-market, do you know what the asset life is?
SKOOG: Sure. On the storage side, it goes up to 2007. However, of the number that Jim gave you I believe was like $85 million roughly. $84 million of that basically comes back to value in 2003. So you don’t have very much of it going out and past. On the transportation contract side 2018, I believe Jim gave you a number of $56 million. Of that $56 million, $50 million comes back by 2005.
MILLER: $36.8 million for 2003. $9.8 million for 2004. If you look at ‘03, the $230 million breaks out, if you look at the $230 million, ‘03 has $145 million. ‘04 has $30.5 million. 2005 has $25 million and 2006 has $18. 2007 has $9 and it just falls off to about $2 …
LUCAS: So just so once again you had physical assets and you had financial contracts. The physical assets were the previous mark-to-market was reversed. Those assets then accrue back to earnings over time.
KYLE: That’s correct.
LUCAS: And the $230 million accrual will come back as $145, $30, $25, $18, $9 over time; is that correct?
KYLE: Assuming those prices are at that snapshot point in time.
LUCAS: All right. All things equal.
KYLE: Right.
LUCAS: And to the extent you add additional physical assets or that will add to the accrual to the extent you enter into new financial contracts, you get additional mark-to-market booked over time as well. But that’s the impact of this, this is the impact of the EITF, essentially.
KYLE: That’s correct.
LUCAS: One other little question I had for you. You had given out this guidance going back to this initial issue of this rough guidance that you gave. I was just curious, when we talked about the $2.20 to $2.30 then you have the gain, and people saying $1.80, et cetera, were you talking about basic earnings when you were talking about that? When we talk about earnings, are we thinking about those earnings as basic earnings?
KNEALE: I say yes, basic and fully diluted. They should pretty much be the same for us going forward. In other words, this does away with the D95 calculation we were looking at. Yes, it’s basic and fully diluted.
LUCAS: So it’s really, they’re one and the same.
KNEALE: They should be, going forward.
LUCAS: So, you’re also saying that in the same graph you’re saying that basic and fully diluted should come out at roughly the same for ‘03 or are we thinking more for ‘04?
KNEALE: Pretty much for ‘03. We have to calculate one month under D-95, January. So that could – our EPS numbers we’re going to have to calculate individually by month and add them together. So you won’t be able to take our full year’s net income and divide by the fully diluted shares for January. Now, 2004 forward that entire issue is gone and basic and fully diluted should be the same on an annual basis.
LUCAS: Thank you so much for the clarification.
OPERATOR: This concludes the question and answer session. Gentlemen, I’ll turn the floor back over to you for closing remarks.
KNEALE: Before Weldon does that, Craig, you asked me questions on pension numbers. I had numbers on one. We have union and things. Let me clarify if I look at our all pension plans we had a credit in the income statement of about $19 million in ‘02 and that credit should be pretty close, $16 million to $17 million in ‘03. I just wanted to clarify that. Weldon?
WATSON: This concludes our fourth quarter 2002 conference call. As I mentioned earlier our fourth quarter income statement numbers will be available on our web site later this morning with the 2002 year-end earnings release. As a reminder our quiet period for our first quarter 2003 earnings will be when we close our books sometime in early April and will extend until the release of our first earnings we’ll provide a date for an earnings release in a conference call later. This is Weldon Watson. We’ll be available throughout the day for follow-up questions concerning today’s conference call. You may call me at 918-588-7158.
KNEALE: I’m having trouble reading numbers and I apologize to everybody. The numbers I gave you were ‘01 was $19 million credit, ‘02 is $16 million credit. And ‘03 should be about $11 million. So I apologize. I’ve just got a whole pile of numbers here and I got confused.
WATSON: OK. Thank you, Jim. On behalf of Oneok, we thank you for joining us today and good day.
OPERATOR: Ladies and gentlemen, this concludes today’s conference. Thank you for your participation. You may disconnect at this time and have a pleasant day.
END
