OGE Energy Corp (OGE) 2003 Q1 法說會逐字稿

Good day. At this time all sites are now on the conference line in a listen-only mode. I would like to turn it over to your host, Mr. Jim Hatfield. Go ahead, please, sir.

Thank you, and good morning and welcome to OGE Energy Corp's first quarter 2003 earnings conference call. I'm Jim Hatfield, Chief Financial Officer for OGE Energy Corp. I have with me today Steve Moore, chairman, president, and CEO; Al Strecker, EVP and COO; Pete Delaney, EVP and CEO of the non-regulated businesses; Donald Rowlett, who is vice president and controller; and Eric Weekes, who is treasurer.

What we're going to do, as we've typically done, is we'll start with comments from Steve Moore, I'll review the first quarter. I have some comments around the 2003 outlook; turn it over to Pete Delaney, who will give an Enogex operations and outlook, and then we'll turn it over for Q&A, and before we get started, I just wanted to point everybody to the Safe Harbor statement that's contained in the earnings release. With that, I'll turn it over to Steve.

Good morning. I'd like to add my welcome to Jim's and thanks for joining us. Today we reported breakeven results for the first quarter, a pretty good wintertime performance for us. Certainly, it's a great improvement over the loss of 8 cents a share we recorded last year at this time. So, overall, we're pleased to be off to a good start.

Our electric utility, OG&E, is dealing with lower rates and higher expenses. The utility recorded a net loss of $3.3m in the first quarter compared with a loss of $1.5m last year. Historically, remember, due to the seasonality of our business, the bulk of OG&E's earnings come in the second and third quarters, and we expect that to occur once again this year, of course. The big story, as far as I'm concerned, is the improved performance of Enogex, our natural gas pipeline. On a stand-alone basis, Enogex earned $5.5m in the quarter, or 7 cents a share, which is an improvement of nearly $7m of net income compared to the first quarter loss Enogex reported last year. We are very pleased with the progress we are making at Enogex. We have restructured the operation, and we continue to redesign its business processes to produce more stable and reliable earnings.

We have completed big steps to reduce the company's business and financial risk, and these steps were put to an extreme test in the first quarter. It was one of the most volatile natural gas pricing environments we have ever seen, and Enogex did just fine. Enogex has benefited from gains associated with asset sales as well as better operating performance. Margins were higher at Enogex in all segments of its business. We are pleased that we have improved our ability to manage that business in the most volatile of times. And with lower debt, after a series of asset sales last year, interest expenses were also lower. Clearly, what we have done and what we are doing at Enogex is working, and we will continue that work.

At OG&E, our utility, we face the challenge of operating a business that is more costly to run with electric rates that are lower this year under the terms of our rate case settlement of last year. The good news is that customer demand for electric power on our system remains strong in all sectors. Total kilowatt sales were up 4% in the quarter. Meanwhile, we continue to work on and make progress toward acquisition of a new power plant. That new power plant will help us fulfill the requirement of additional customer savings that we agreed to in our rate case settlement of last year. As a regulated asset in our rate base, it fits our business strategy as a utility-focused enterprise pursuing thoughtful, conservative growth.

We have filed shelf registrations with the SEC to issue new debt and equity to finance that acquisition. We also plan to seek regulatory approval of the acquisition and issue those new securities later this year.

I want to thank you for listening. I appreciate your continued interest in our company. I continue to believe very strongly that you have made a good investment, and at this time I'd like for Jim Hatfield to go over the quarter in a little bit more detail. Jim?

Thank you, Steve. I would now like to cover the earnings of OG&E Energy Corp. I'll start with a discussion of the first quarter -- discuss the contributions of the business units in the quarter, and then comment on the 2003 outlook.

I'd like to point out a couple of presentation items in the financials. In prior calls we discussed discontinued operations. In February we closed on the sale of our NuStar joint venture. The NuStar joint venture consisted of gathering and processing assets in West Texas. With that sale we have now completed our planned asset sales. These sales have generated approximately $108m. All the financial information related to the assets, including cash flow information and gains on the sale of the assets, are contained in one line item on the financials under "Discontinued Operations."

Additionally, we completed the sale of a 29-mile segment of the Ozark pipeline in January 2003. The gain on the sale of this asset is recorded under "Other Income" in the financial statement. Finally, as we mentioned in our prior calls, we recorded a charge of 9.6m, on a pretax basis, related to the cumulative change in accounting principal related to the implementation of the EITF 0203 in the first quarter. This is recorded as a separate line item in the financial statements as well. I'll discuss the impact of this cumulative change in greater detail when I discuss Enogex.

Now for a discussion of the first quarter -- we reported a breakeven quarter as compared to a loss of $6.2m, or 8 cents per share in the first quarter of 2002. The breakdown by business unit on a comparative basis is as follows: Energy Corp, the holding company, a lost of 3 cents as compared to a loss of 4 cents in 2002; OG&E, the utility, a loss of 4 cents as compared to a loss of 2 cents in 2002; and Enogex, income of 7 cents as compared to a loss of 2 cents in 2002.

Looking at OGE Energy Corp, the holding company, a loss of 3 cents as compared to a loss of 4 cents in the first quarter of 2002. The holding company recorded lower interest expense as a result of the lower interest rate environment.

For OG&E, a loss of 3.3m, or 4 cents a share as compared to a loss of one-half million, or 2 cents a share in 2002 -- the components of operating results are as follows: The revenue net of fuel was up $5.5m, or 3 cents a share. The components of that revenue -- our growth was up about 5.2m, or 3 cents a share; the ECR rider in Arkansas, 2.9m or about a penny a share; the effect of the ice storm in 2002, million and a half dollars, or 1 cent a share; weather, a million dollars, or 1 cent a share. These were offset by the rate reduction of 4.2m, or 2 cents a share, and other $900,000, or a penny a share.

As Steve mentioned, we did experience strong growth in electric sales in the first quarter with system sales up 4% from the first quarter in 2002. I mentioned the positive benefit from the ECR. The ECR is a fuel-recovery mechanism in Arkansas. In the fourth quarter of 2002 the accounting for this rider was changed to a fuel recover will neither positively nor negatively impact the earnings of OG&E, which is consistent with the Oklahoma treatment. However, prior to the fourth quarter we had the potential to over or under collect fuel as a base was reset every April 1. The positive contribution of $2.9m represents under collection in last year's first quarter. This is a timing issue, as we will see a positive variance in the second quarter and a negative variance in the third quarter but no financial impact for 2003 as a whole.

I mentioned the positive contribution related to the 2002 ice storm -- as you know, we lost revenue associated with the interruption of service to our customers in that January 2002 ice storm. We also had favorable weather in the quarter, exceeding degree days that were 6% above normal, 5% above the 2002 quarter. These positive results were partially offset by the rate reduction, which took effect in January and a loss of the GEP rider.

Turning now to O&M expenses, which were up $7.3m, or 4 cents a share at a level of $72m -- the components of the increase in O&M are the impact of the ice storm, $5.4m, or 3 cents a share; outside services, 2.3m, or a penny a share; pension and benefits, up about 2m, or a penny a share; offset by lower uncollectibles of $1.2m, or a penny a share; and other, $1.2m, or a penny a share.

Let’s talk about the ice storm -- the negative impact is really the result of expenses, which were accounted for as a regulatory asset in 2002, which normally would have been accounted for as maintenance expenses. The increase in outside services is really labor primarily attributable to contract labor associated with the overhaul of one of our turbines. Higher pension and benefit costs are the result of a general upward trend in these costs. These increases were partially offset by lower levels of uncollectible accounts and other is really primarily the result of lower levels of overtime in this year's first quarter compared to last year's first quarter.

Depreciation expense increased about 1.8m, and that represents the first-year amortization of the regulatory asset, all of which was collected in the first quarter. Consistent with our guidance, utility was negatively impacted by higher O&M expenses and the rate reduction.

For Enogex, net income of $5.5m, or 7 cents a share as compared to a loss of $1.3m or 2 cents a share in 2002. The gain on the sale of the Ozark asset contributed 2.4m on an after-tax basis. Therefore, excluding the gain on the asset sale, Enogex contributed 3.1m, or 4 cents a share.

As Steve pointed out in his comments, we are pleased with the improved operating results at Enogex in the first quarter. The components of net income are as follows: Gross margins increased 29% from 48.8m in 2002 to 63.1m in 2003. The gross margin contribution by business is as follows: Transportation and storage, $27.7m in 2003 as compared to 26.3m in 2002; gathering and processing, $22.1m in 2003 as compared to $17.3m in 2002; and marketing and trading, 13.3m in 2003 as compared to 5.2m in 2002.

Looking at the businesses, the increase in transportation and storage gross margin was driven primarily by higher demand fees associated with the Stewart [ph] Storage Facility in piece paid by the marketing and trading affiliate. Gross margins also increased due to increased interruptible transportation revenue on the Ozark pipeline system, the result of higher volumes and prices. Better storage results were partially offset by lower demand revenues in the transportation business as a result of contract revisions and expiration. The decrease associated with contract revisions is a timing issue as decreases and contractual payments in the first and fourth quarter will be made up by increases in contractual payments in the second and third quarter.

The increase in gathering and processing gross margin was the result of better performance in the processing business as compared to 2002. Processing gross margin was 9.4m in 2003 as compared to 5.5m in 2002. The major factors in the increased gross margin were the treating fee of 1.8m and the true-up of a period accrual of approximately 1.8m. Although volumes were off, average realized prices were up. Average gross margin per gallon of NGLs was 13.8 cents in 2003 compared to 7.1 cents in 2002. Gathering gross margin was 12.7m as compared to 11.8m in 2002, as volumes were up 18% primarily reflecting the impact of reduced volumes in 2002 -- again, the result of the January ice storm.

The increase in gross margins and marketing and trading was a result of 10.2m sale of gas and storage during the first quarter of 2003. That gain was the result of Enogex recording a cumulative effect of a change in accounting principals in the first quarter of $9m, pretax, as a result of EITF 0203. The change in accounting principals relates to recording storage revenues under the accrual method as opposed to mark to market.

Therefore, as with the impact of the change in accounting principal, gross margins would have been 4.3m as compared to 5.2m in 2002. The decrease in gross margin is the result of higher demand fees paid for storage to the affiliate pipeline as well as lower margins on power sales.

I'd like to point out that we discussed the unknown impact of the implementation of EITF 0203 when discussing our 2003 guidance. Now that the first quarter is behind us, I'm happy to report that we more than offset the negative impact in the first quarter.

Overall, expenses were lower, resulting in operating income of $25.2m as compared to 8.8m in 2002. Operating expenses were 22.4m, down from 24m in 2002; net interest expense was 9.9m, down from 12.7m in 2002. Additionally, discontinued operations contributed 1.3m as compared to 2.1m in 2002.

In summary, despite the volatility in commodity prices in the first quarter, processing gross margin was up over last year, and the other businesses performed as expected.

In terms of the 2003 outlook, at this point we continue to see the range of net income -- $1.35 to $1.45 a share. We're still projecting OG&E to earn between 112m and 118m, and the holding company to lose approximately 14m. However, we have raised the projection on Enogex to 16m to 18m, up from 14m to 16m we previously discussed. The increase in projection is due to stronger operating results in the first quarter. I'd like to point that over 90% of the company's consolidated net income falls in the second and third quarter of the year.

I'd now like to turn it over to Pete Delaney, who will discuss the operations and outlook at Enogex.

Thanks, Jim. I'd like to take a couple of minutes to supplement Jim's overview of Enogex's first quarter results and discuss our outlook for the year.

We were pleased with the improvement in earnings in the first quarter over 2002, particularly given the extreme volatility we saw in natural gas prices. We believe the quarter validates the steps we are taking; namely, instituting a default processing fee or treating fee, as it's also called; actively hedging liquids prices; and optimizing our operations to reduce earnings volatility.

A quick review of the transportation storage gathering and processing and marketing business will provide a perspective on the outlook for 2003. The transportation margin outlook was driven largely by firm demand charges from OG&E and [inaudible] and two independent power plants, and that remains on track. We continue to realize improvement in our fuel use on the pipeline due to improvements we have made over the last 12 months in the field operations area. We saw improvement in 2002 over 2001 resulting in a favorable earnings impact from fuel recovery, and this improvement continues in 2003. We fully expect at this time to realize the 7m in additional fuel recovery that we had planned in the latter half of the year.

On April 29th, the utility had filed with the commission a new transportation storage agreement with Enogex. This seven-year agreement provides for historical gas transportation services at the same rates coupled, however, with higher contracted transportation needs. The agreement also provides for the storage service previously provided to OG&E from the Stewart storage facility and replaces the separate interim agreement that was in place. The storage services were built previously under an interim agreement until the ownership of the facility was secured in the latter half of -- in late 2002. The new agreement provides for a premium no-notice load following services and by incorporating the storage services in the contract. That storage service is no longer asset-specific but has the backing of Enogex fully integrated system. Additional revenues will be realized due to the higher contracted transportation needs the market raised for the premium storage services.

Also, as discussed in the year-end call, we had gas losses at the Greasy Creek storage facility. We made some repairs to address the issues that we are aware of. Shut-in tests completed in April indicated that losses did continue during the first quarter until the repairs were made. We are evaluating alternatives for potential recovery of this gas and will perform another test early this summer. We are deferring taking any action -- any financial action or financial impact -- until we can determine the probability of recovery of all or a portion of the lost gas.

We had an outstanding Farmland receivable of 1.6m coming into the year net of last year's write-down. That receivable at this point will be paid in full by Coe Majugen [ph] under their terms of purchasing the Enid fertilizer facility out of the bankruptcy proceedings. We actually will recover this year an additional $300,000 for that receivable, and the agreement allows us to participate in any incremental recovery up to an additional $800,000 if other unsecured creditors receive higher amounts of recovery. Considering all these items that I’d mentioned above, we expect our margins from the transportation and storage segment to increase over plan by roughly $3m to $4m.

The gathering business is on track. We have seen a response to higher gas prices with a rig count in Oklahoma up around 20% from year-end 2002. Our well connects are just about on plan with volume slightly above plan at this time, and volume above levels that they were at the beginning of the year. This is despite the fact that volumes were negatively impacted in February for freeze offs, but have rebounded quickly in this high gas price environment, unlike our experience in early '02.

We expect the positive variance to increase throughout the year, based on the lag between drilling and production. We also continue to increase our gathering rates on existing volumes as shown by the higher [inaudible] of margin. These increases were factored into our original projection.

On the processing margin side, the first quarter was above plan on an operating basis for several reasons, but first we hedged 89% of our POL volumes above budget for a positive variance of $140,000. Liquids prices in January and February increased dramatically, somewhat offsetting the higher natural gas prices such that defaulting processing fees were not invoiced -- or the treating fees were not invoiced for volumes during those months. March was a different story. In that month we charged a treating fee on our high liquid [peep-hole] volumes that resulted in about $1.8m contribution to our processing margin. In addition, optimizing the operations of these plants during all these months allowed us to capture incremental margin.

You may recall this treating fee was part of the FERC 311 case settlement that is involved in the FERC and is retroactive November 1st. We expect an order out of FERC approving the settlement that was in the 60 to 90 days, depending on when it gets on their docket.

We expect conditions will dictate our treating fee in April as well, but not to the extent invoiced in March, and despite the physically higher natural gas prices projected than planned, we are holding to our originally projected processing margin that we set out for 2003. We have hedged, at this point, approximately 79% and 71% of our projected POL volumes above plan in the second and third quarters, respectively. In addition, we have hedged approximately 15% and 16% of our [peep-hole] volumes above prices that spread above plan for those same periods.

The marketing business continues to perform well and tracks to meet their originally forecasted numbers. The first quarter plan based on additional margin driven, we believe, by the higher volatility of the gas prices around our transportation storage asset resulting in the higher margins for all the products and services sold.

Despite better-than-planned numbers so far, we are holding to our numbers, given current weakness in storage values as well as the uncertainty around the amount of margin that may slide into the first quarter of 2004 from the last quarter in '03 as a result accounting rule changes involving FAS 333 that were not clarified until the middle of the first quarter.

We are off to a strong start this year, particularly given the volatility in natural gas prices and the more challenging processing environment than we had planned on. However, we are just through the first quarter and in the steps above we have identified some potential issues ahead of us that we need to manage.

On balance, we are increasing our guidance for net income to $16m to $18m for 2003. We are continuing to implement our strategy to continue to improve the performance of the company in all areas. Jim?

Thanks, Steve. And, with that, those are our prepared remarks. We're going to turn it over to Q&A at this point.

At this time, if you would like to register your site for a question, please press the star, then the 1 on your touchtone phone. Once again, if you would like to register your site for a question, please press the star, then the 1 on your touchtone phone. We will first go to the site of David Frank from Zimmer Lucas Partners.

Hi, good morning, guys.

Good morning.

Jim, could you just tell me again what the gains were at Enogex? I think you had gain on sale and EITF pretax gain of about $9m?

The gain on the sale of the Ozark asset was 2.4m after tax. The EITF 0203 implementation actually was 9.6m negative after tax, I think about 5.7, which is primarily in the marketing segment. However, that negative impact of the implementation of 0203 was offset by positive margin and associated basically withdrawing gas out of storage -- a gain on the sale of the storage about 10.2m.

10.2 -- okay, so if I was to net out the 9.6 and the 10.2 --

That ought to cut $600,000 on the margin basis pretax.

On pretax and -- and so on an earnings per share, just real fast, the gain on the sale of 2.4m after tax, how much was that?

About 3 cents.

About 3 cents -- so your operating number was closer to -- I'm going to guess -- something like a 4-cent loss on the quarter?

Operating was more like a 3-cent loss on the quarter, I think.

All right, I didn't know what the 600,000 was.

Well, you have some -- sort of -- implementation -- accounting principal offset by the accrual accounting gain on that. That's what the 600,000 represents.

Okay, and do you have an update as to where you stand on your -- what the outlook is right now for acquisition of generation plants within your service territory and when you might present something to the commission out there?

This is Pete Delaney talking -- we, as you know, have three merchant power plants in our area without long-term agreements that we have identified. We continue to have discussions and, at this point in time, that's all we're going to say about that.

Okay, well, thanks a lot.

Our next question comes from the site of [Zack Schreiber] from Duchesne Capital.

Actually, it's Zack Schreiber at Duchesne Capital Management. David got most of my questions, Jim. I just wanted to see, in terms of the utility -- where are we? Does this guidance thing run 118m equate to on a financial -- on a regulated basis, and it seems -- and what was the weather benefit of the quarter? If you could just kind of quantify it, and that's really it.

Well, the weather benefit in the first quarter was about $1m, and the 112 to 118 represents regulated ROE on the high side of the guidance would be RNR [ph] allowed return, which is 1155 plus the 50 basis points ITC. On the low side, obviously, it would be somewhere around 10.8%, 10.9%. So that would be the range of earnings within the utility guidance.

Okay, thank you so much.

Thank you, Zach.

We will go next to the site of Doug Fischer from AG Edwards.

Thank you. Could you clarify the weather benefit we're talking at the utility -- is that pretax, is that after-tax, is that versus normal, is that versus last year?

The $1m is a pretax, basically a gross margin basis, and that is versus -- that's based on comparison to '02. We were 6% -- heating grade A 6% above normal, 5% above last year. Last year really represents pretty much normal weather.

Okay, so roughly speaking it was a 1m pretax gross margin versus last year and versus normal.

Yeah, basically.

Okay, and I didn't quite understand what Pete Delaney was saying about some of the accounting changes. Was he referring to -- you know, at the end of his comments, I think he was talking about some challenges, you know, I mean, some things have gone better, but there are some challenges. Was he talking about the accounting change -- some kind of accounting issue that affects '03 versus '04? Or was he talking about '02 versus '03?

Doug, on that issue, if you remember our last call, we talked about the implementation '02, '03, and change from mark-to-market to accrual, and we didn't know what that first quarter impact was going to be, but we knew it was a timing issue, and what Pete is referring to is the same issue as it relates to fourth quarter '03, first quarter '04, which is really what is the impact of moving from mark-to-market to accrual -- the storage -- and does margin move from fourth quarter '03 into the first quarter '04. It's an impact that, right now, it's hard for us to predict when we think about their earnings potential of marketing and trading as it relates to '03.

But you still feel comfortable raising the guidance for the year despite that uncertainty?

That's correct, and it's for, you know -- that's correct.

Remind me of the old guidance -- you raised it to 14 to 18. The old guidance was 14?

It was 14 to 16 was our prior guidance. We're moving the range up to 16 to 18.

Okay, all right. I think -- and then, just, on what David had said on these gains, you're saying basically the asset gain is Ozark, and then the ETIF is a minus 5.7m, and then the accrual gain back was a 10.2 on a pretax basis, is that what you're saying?

Correct, correct.

Okay, thanks, sorry for rehashing that.

No, thank you, Doug.

Our next question comes from the site of [David Grumhaus] from [Kobia] Capital.

Good morning, guys. Most of my questions have been answered, but a couple of quick ones for you -- was Ozark the only asset sale gain in the quarter or was there another one as well?

There was a gain on the NuStar joint venture. That is contained in the discontinued operations line, which is 1.3, I think, versus 2.2m in 2002's quarter.

Okay, so Ozark is the only thing in the continuing operations number?

Correct.

You had mentioned, I think, in a true-up accrual of about 1.8m -- what exactly is that?

Well, what we, in our business, typically would close any particular month on estimates of volumes, and we always true those up and to par them up, we had an estimate of revenue in December that was trued up in January, and it was 1.8m, pretax, higher than what was in our estimate number. So it's just a result of closing month-to-month business.

Okay, and, lastly, any more -- I know you've touched on it a little bit, but any more specific timing on the planned purchase in the equity deal? I mean, I assume they're going to come one -- it will be announced pretty much around the same time. You won't do one without the other? Is that fair?

In terms of the power plant, again, you know, we just are -- in discussions, and we really aren't in a position to say any more about that or talking about any financing.

Okay, but the financing we'll wait for the announcement on the power deal. Is that a fair statement on the power plant?

I don't know if that decision has been made at this point in time.

All right. Thank you very much.

Our next question comes from the site of [Kevin Geogagin] from [Luminous] Management.

Hi, guys. Thanks for the time today, I appreciate it. I'm sorry to re-ask this question -- I just got on the phone call. Just so I could know -- I guess -- organic EPS was off the 5.7, I think it was, and then the asset sale gain was -- or -- I'm sorry -- 4.3, and then you said the Ozark asset gain was 5.7m net income? And then can you tell me the weather impact again on the net income?

You're talking about Enogex?

Yeah, I apologize, I just jumped on the call.

Yeah, okay, Enogex earned, for the quarter, was $5.5m. That includes the after-tax impact of the gain on asset of 2.4. And then weather impact for the quarter was about $1m gross margin contribution at the utility.

Okay, so not, like, a half million or something like that? I think that's all my questions, thank you very much.

Okay, thank you.

Once again, if you would like to register your site for a question, please press the star then the 1 on your touchtone phone. Our next question comes from the site of Doug Fischer from AG Edwards.

Just to clarify your guidance -- your earnings guidance excludes the discontinued ops, right?

No, that would include discontinued ops in the 16m to 18m at Enogex.

So the 16 to 18 includes discontinued ops?

Yes.

And are those discontinued ops expected to be positive for the year?

Yeah, we had 1.3m in the first quarter. We will not have any more discontinued operations, going forward. The last asset sale was NuStar in February, as I said, at this point we're done with the planned asset sales.

Okay, so the discontinued ops -- so both of the asset sales are in Enogex. The in operations is the Ozark unit, and in discontinued ops is the NuStar.

Correct.

Okay, all right, I just wanted to clarify that. Thank you.

Thank you, Doug.

We will go back to the site of [Kevin Geogagin] from [Luminous] Management.

Sorry, one more question for you guys. In terms of the accrual -- you mentioned the accrual earn back. Is that a portion of your business that's -- you know, I know some people have been subtracting out those earnings as sort of one-time accrual gains or earn back gains. Is that part of your business that's going to be there next year that I should just assume as sort of an ongoing level?

Yeah, that accrual versus mark-to-market and one time is predominantly part of the marketing and trading business, which will be an ongoing activity that we continue at Enogex.

Okay, great. Thank you very much again.

Our next question comes from the site of [Adula Muhrti] from SAC Capital.

Good morning. I've been in and out on this call, so I apologize if this has been addressed in some fashion. I know you discussed the idea of buying a power plant and putting in the rate base, and I think you'd indicated that -- a little uncertain in terms of timing and financing. Can you just remind us, at least in the past, what you've indicated as to what you thought roughly would be a range in terms of potential investment in a generation asset at this point in terms of how much capacity you're looking for and in terms of the shelf -- how large that shelf is and percentage of capitalization you'd like to finance whatever you end up doing?

In terms of the plant investment, the order that was assigned in 2002 said at least 400 megawatts. So from a planning perspective, we're looking at around 400 megawatts, and, you know, what we've talked about before in terms of -- for planning purposes, around $400 of KWs, so that would make it about 160m. Our current ratio that was out of the last case is 56% equity, so that would be around $90m at 160. Our equity shelf was filed at 130m and the debt shelf was, I think, 200m, and so that would essentially be the planning assumptions around the power plant.

And in terms of this year's $1.35, $1.45 outlook, is there any dilution or negative carry associated with the acquisition of this plant for a period of time and the financing being kind of in place while you're still waiting to kind of close and get the rate treatment and everything like that?

Yeah, the assumption of shares outstanding -- average shares outstanding -- are about 83.5m within the guidance, and that would then, say, we have 5% to 6% dilution embedded in the guidance for a negative carry for 2003.

Okay. All right, thank you very much.

It appears we have no further questions at this time.

We'd like to thank you very much for your investment and interest in the company and particularly like to thank you for joining this morning. Good day.

That concludes today's conference. You may disconnect at any time.