Duke Energy Corp (DUK) 2003 Q4 法說會逐字稿

Good day, everyone, and welcome to the Duke Energy fourth quarter and year end earnings conference call. Today's call is being recorded.

At this time for opening remarks, I would like to turn the call over to the Vice President of Investor and Shareholder Relations for Duke Energy, Mr. Greg Ebel. Please go ahead, sir.

Thanks, Paula. Good morning, everybody, and thank you for joining us.

With me today are Paul Anderson, CEO and chairman of Duke Energy and David Hoosier, our CFO, in addition Fred Fowler our Chief Operating Officer and Myron Caldwell, our Treasurer, with us to assist with any questions you may have.

Today's call will be focused on the results of the fourth quarter and full year 2003. I know many of you are eager to get more information on our medium term outlook following our conference call just a few weeks ago.

Our key business unit leaders will be in a position to have that discussion with you on February 3rd, when we come to New York for a half day analyst meeting.

Before we get going today, let me read our Safe Harbor statement. Some of the things we will discuss in today's call concerning future company performance will be forward-looking statements within the meaning of securities laws.

Actual results may materially differ from those discussed in these forward-looking statements, and you should refer to the additional information contained in our SEC filings concerning factors that could cause those results to be different than those contemplated in today's discussion.

In addition, today's discussion includes certain non-GAAP financial measures as defined under SEC Reg-G.

A reconciliation of these measures to the most directly comparable GAAP measures will be made available on our investor website at www.Duke-energy.com.

Following Paul's and David's prepared comments, we'll open the line up to your questions. With that, let me turn to Paul for some opening comments.

Thank you, Greg. I'd like to begin by noting that 2003 has been a year of transition for Duke Energy.

We were quite successful in reversing the trajectory of the company and establishing a stable platform on which we can build.

Despite these accomplishments, and to a certain extent because of them, we're reporting the largest loss in the history of the company.

As you have no doubt seen, Duke Energy reported a net loss of $1.48 per share for 2003, which included $2.76 in special items, which we'll cover in more detail in just a minute.

Reported earnings for 2002 were $1.22 per share, and included charges for special items totaling 66 cents per share. Most of our business segments continued to deliver strong results for the quarter and the year.

Gas Transmission, Field Services, Internal and Crescent met their earnings targets and produced good cash flows.

Natural Gas Transmissions recognized it's first full year of earnings from the West Coast assets, and Field Services benefited from higher NGL prices and improving frac spreads.

Internal's Latin American assets delivered expected results. And National Methanol had record output during the year. Decreased earnings for the year at Franchised Electric reflected higher depreciation, amortization and O&M cost. The lower sales in our service territory, due to unfavorable weather for the year, were offset by higher off-system sales to wholesale customers.

DENA's ongoing results for the year reflected the continued oversupply of merchant generation and low spark spreads, which have precluded many of our facilities from generating cost effective power.

As we discussed in our call earlier this month, we took a number of charges for asset impairments at both DENA and DEI, and for costs to wind down the Duke Energy trading and marketing joint venture.

With these decisions behind us, DENA can now focus on divesting plants in the southeast and contracting more power supplies from our remaining facilities.

As part of our cost reduction efforts across the company, Duke Energy incurred approximately $153 million in severance costs during 2003.

Annual cost savings related to the workforce reduction and other cost savings initiatives will reach at least $200 million in 2004.

During this month, I shared with you some charges we planned to take during the fourth quarter. I'd like to update you on where we are regarding those charges, as well as other charges which will make up our special items for 2003.

Now, this table has a lot of numbers on it, and I'm not going to walk through each item on the table, as we have already provided you with information concerning these charges in previous calls.

But I thought you needed to see a table that summarized all of the special items included in our reported EBIT numbers. As you can see, the most significant items shown here have to do with the fourth quarter 2003 asset impairments of DENA, the associated disqualified hedges, and the wind down of Duke Energy trading and marketing.

The third quarter goodwill write down was the most significant charge not in the fourth quarter.

In addition to the numbers shown here, other special items totaling approximately $170 million are included in our financials as net losses from discontinued operations net of tax.

We've put this information out to help you better understand what our 2003 ongoing EBIT from continuing operations are for each of our reporting segments. With that, let me turn things over to David.

Thank you, Paul. For the fourth quarter of 2003, Duke Energy reported a loss of $2.23 per share.

Excluding the $2.45 in special items for fourth quarter discussed earlier, ongoing earnings were 22 cents per share.

As you may likely have noticed, we are now reporting discontinued operations. This is the first time that we have had the income statement line "Discontinued Operations". It is the accounting fallout associated with our fourth quarter decision to exit certain businesses.

The "Discontinued Operations" line is net of both interest expense and income taxes. As this change affects past periods, we have re-classified for prior periods.

Looking forward, this should provide you with a better view of our ongoing earnings. Now let me move onto the specifics at the business segments.

Franchised Electric reported segment EBIT of $197 million for the fourth quarter of 2003, compared with $248 million for the same period in 2002.

Excluding $29 million, primarily related to severance charges, ongoing segment EBIT for the fourth quarter of 2003 was $226 million. While our ongoing EBIT was lower than originally anticipated, the cash flow generated in 2003 was in line with our projections.

Primary drivers for the quarter were reduced revenues for milder weather, lower wholesale power sales, and higher depreciation, amortization, and O&M expenses. Additional clean air amortization and the new Mill Creek plant, along with other capital additions, contributed to higher depreciation and amortization expense.

During the fourth quarter, Franchised Electric increased its North Carolina clean air amortization expense by $10 million from its originally projected amount, for a total of $28 million. Clean air amortization for the year totaled $115 million, approximately $45 million more than our original estimate for 2003.

We saw heating degree hours decrease 12.8% from last year's fourth quarter. This warmer winter weather decreased gigawatt hour sales by about 7% from the fourth quarter of 2002.

Residential and industrial sales decreased by 7% and 5 1/2%, respectively. The number of customers increased by 1.9% compared with fourth quarter last year.

For the full year, you will notice that our reported earnings for Franchised Electric are about $200 million lower than in 2002. This lower earnings number is consistent with both our current rate base and our allowed returns in North and South Carolina.

Now let me move on to Natural Gas Transmission. Our gas transmission business in the U.S. and Canada delivered $308 million in segment EBIT for the fourth quarter of 2003, compared with $294 million in 2002. When adjusted for special items, EBIT for both quarters totaled $303 million.

Special items during the fourth quarter of 2003 included gains on asset sales of $16 million and an $11 million charge for severance and related costs.

Flat earnings quarter over quarter was the result of foregone earnings related to asset sales during 2003, partially offset by incremental earnings from expansion projects.

Natural Gas Transmission delivered solid results and exceeded its forecasted annual EBIT target of $1.2 billion, despite foregone earnings associated with certain asset divestitures.

Overall, Field Services ongoing EBIT for the fourth quarter was about $10 million higher than last year. Earnings benefited from the improvement in NGL pricing -- although hedges against movements in NGL pricing partially offset the price increases.

Field Services realized strong margins from its processing business, especially on percent of proceeds contract margins, which increased nearly 35 million over last year's fourth quarter.

Natural gas liquids prices continued to improve over last year, from 45 cents in the fourth quarter of 2002 to 54 cents in the fourth quarter this year. NGL so far in the first quarter of 2004 have averaged about 66 cents per gallon.

The frac spread was about $1.81 for MMBTU at the end of the fourth quarter, about $1 higher than the third quarter. We have seen frac spreads continue to increase in January as well.

Weighted average NGL prices for the full year also showed similar improvement -- 58 cents compared with 45 cents in 2002.

Operating costs during the quarter were about $20 million higher than last year, primarily due to some $20 million in fourth quarter '03 charges for severance and other employee-related expenses.

Going into 2004, we expect direct operating and G&A expenses to average about $575 to $600 million. Field Services continues to work on adding minimum fee clauses to a portion of it's key poll contracts. These clauses could be exercised in the event of weak frac spread pricing environments.

And we have also transitioned some key poll contracts to percent of proceeds contracts. This transition has had the affect of neutralizing the sensitivity to changes in natural gas prices.

Field Services' sensitivity to a 10 cents per MBTU -- MMBTU change in the price for natural gas now equates to a less than $1 million change in segment EBIT, with a negative correlation, where it was about 5 million before.

Sensitivities to NGL prices have also changed. At the Duke Energy level, net of all hedging, the sensitivity is approximately $6 million in segment EBIT, for a 1 cent change in NGL prices. The NGL sensitivity is positively correlated.

At the 100% Field Services level, without hedging, a 1 cent per gallon change in NGL prices moved segment EBIT by about $18 million, compared with the prior sensitivity of $25 million.

This reduction is largely driven by the movement from key poll contracts to percent of proceeds contracts. The transition to more percent of proceeds contracts essentially reduces the volatility in earnings related to NGL price fluctuations.

DENA's results for the quarter continue to reflect the poor market conditions for the merchant energy business. Continued downward pressure on spark spreads severely limited our ability to capture value in the marketplace.

Higher depreciation expenses associated with new projects added over the last year also contributed to the EBIT loss. DENA reported a fourth quarter ongoing EBIT loss of $74 million, compared with a positive $63 million last year.

The major variance between reported EBIT and ongoing EBIT is the approximately $3.1 billion in special items taken in the fourth quarter of 2003.

These charges related to the asset impairment of DENA's southeastern plants, and the deferred western plants, wind down costs associated with the DTM joint venture and re-designation of certain hedges from accrual to market to market that are related to the impaired assets.

During the fourth quarter of 2002, DENA had special charges of $41 million, made up of workforce reductions of $7 million, demobilization costs of $10 million, and a $24 million charge for an information management system writeoff.

At Duke Energy North America, total gross margin realized in 2003 amounted to $653 million. Low risk gross margin totaled approximately $600 million for the year, which is consistent with the amount we have been expecting and have discussed with you previously.

Offsetting total gross margin were operating expenses totaling $722 million for depreciation, operating and maintenance, G&A, and minority interest expenses, which results in an annual ongoing EBIT loss before special items of $69 million.

G&A expenses were higher in the fourth quarter, due to charges for bad debt and severance expenses and a contract dispute reserve. You can see that we have also included the special items recorded in the fourth quarter of 2003 to reconcile to our reported segment EBIT.

The Committee of Chief Brisk Officers table is something that you're all familiar with. I wanted to bring to your attention that we have removed the southeast assets from all years shown, because we are pursuing the sale of these assets.

We have also excluded the capacity associated with the deferred plants beginning in 2005, when they were expected to be in service. You can see we have sold approximately 93% of our estimated production in 2004 at about 66% in both 2005 and 2006.

The average price per megawatt hour for these sales is $44 in 2004, $45 in 2005 and $42 in 2006. Additionally, we have purchased in excess of 80% of the gas needed to meet production sold for each of the years shown in the table.

For the fourth quarter of 2003, Duke Energy's internal operations reported EBIT from continuing operations of $36 million, including a $26 million charge for an environmental reserve related to our Brazilian operations. Excluding this charge, ongoing EBIT was $62 million.

Reported EBIT for the fourth quarter of 2002, as restated to remove the effective discontinued operations, was 23 million. Ongoing EBIT for the fourth quarter of 2002 was $27 million.

Internal Energy's ongoing operations proud favorable results for the quarter, reflecting positive results from the Latin American operations and National Methanol.

Earnings and special charges from the company's Australian and European businesses, as well as results from PJP, have been re-classified to discontinued operations for the current and prior years. For our "Other Operations" segment, I'd like to briefly review the largest component in that segment, Crescent Resources, our real estate business.

Crescent reported 2003 EBIT of approximately $150 million, which was in line with our expectations for the full year, as was their cash generation.

For the entire year, we reached a total of more than $2 billion in gross proceeds from asset sales, far exceeding our original expectation of $600 million. And it's important to note that these were not power sales. We realized good value for these assets.

The after-tax proceeds associated with our 2003 asset sales are approximately $1.8 billion. For 2003, the impact of foregone operating income was approximately $150 million.

The annualized impact on operating income going forward will be approximately $245 million.

Proceeds from our 2003 asset sales have contributed greatly to our ability to reduce the company's debt balances.

We are actively pursuing the sale of our generation assets in the southeast, and the sale for IPO of our Australian energy business is well under way. We have hired financial advisers to assist us in these transactions.

Expected proceeds from these transactions are approximately 1.5 billion. The completion of these asset sales will substantially reduce the company's exposure to merchant generation and internal operations.

Before I move on to the discussion of debt reductions, let me review the change in interest expense. Duke Energy reported a $283 million increase in interest expense in 2003 compared to 2002.

With our $2.2 billion reduction in debt during the year, you might reasonably have expected a decrease in interest expense. A few of the significant reasons for the increase are: $136 million decrease in capitalized interest at DENA and Crescent.

$48 million interest on trust preferred securities re-classified for minority interest expense. $46 million due to full year affect of the West Coast acquisition. $16 million writeoff of unamortized debt cost in the Duke Power settlement with the South Carolina Commission.

There are myriad other factors affecting interest, but these are just some of the other significant ones. As we begin to realize the full year effect of the $2.2 billion decline in debt in 2003, and the additional debt reduction in 2004, we'll see considerably lower interest expense going forward.

In 2004, interest expense should be about $1.3 billion. And in 2005, about $1.1 billion. This slide illustrates the changes in debt balances for 2003 and 2004.

At the end of 2003, we had a total debt balance of approximately $22 billion. We have exceeded our plans for debt repayment, and reduced overall debt, including trust preferred securities, by $2.2 billion at Duke Energy.

Reductions at Duke Capital reached $3.7 billion. The total planned debt reduction for 2003 was originally $1.8 billion. Over the next 12 months, we expect to reduce overall debt by approximately 3 1/2 to 4 billion.

These reductions will take place through the mandatory conversion of the equity units in May and November, asset sales, debt maturities and other reductions. We plan to retire all economically callable debt and trust preferred securities in 2004.

Included in this debt reduction amount is the approximately $900 million of debt related to our Australian business.

Because the operations of this business are now considered discontinued operations for accounting purposes, the debt associated with these operations was re-classified on the ballot sheet to "Liabilities Associated with Assets Held for Sale".

At the time the assets are sold, the associated debt will be removed from the balance sheet.

The combination of debt reductions of $3.1 billion, excluding the Australian debt, and new equity issued as a result of the mandatory conversion of debt to equity, will significantly improve our debt to cap ratio from 58 to 52% in just one year.

Both of these numbers reflect the impact on our equity balance of the impairments taken at the end of 2003. Strengthening the balance sheet has been a top priority for the company.

We have maintained an appropriate level of liquidity and have ready access to funds for our day to day business operations. At Duke Energy and Duke Capital, we currently have a total unused capacity of $2.3 billion dollars in credit facilities and letters of credit.

In addition, we had cash on hand at December 31st in excess of $1 billion for additional liquidity purposes, and we expect to maintain this level of cash throughout 2004.

I'll now turn the call back over to Paul for his closing remarks.

Thank you, David. Before we take your questions, let me review the company's achievements in 2003.

First, we were successful in selling nonstrategic assets for more than $2 billion in gross proceeds. Our Cap Ex for the year totaled less than $2.8 billion.

This is a $400 million reduction from our original forecast of $3.2 billion. These accomplishments allowed Duke Energy to reduce debt in 2003 by approximately $2.2 billion and approximately $3.7 billion at Duke Capital.

We're off to a strong start in our debt reduction goal, having exceeded our 2003 projections.

Our current plan, which we shared with you on January 7th, will result in debt reduction of approximately $6 billion in the two years ending December 4 -- December of '04 -- versus our original goal of $5.5 billion in debt reduction over the three years ending 2005.

In other words -- this is very important -- we are one full year ahead of our plan. We discussed a change in management's view of DENA and DEI that resulted in approximately $3.4 billion in pre-tax charges.

In 2004, we expect to reduce the size of these operations, along with reducing the risk of exposures inherent in these businesses. We expect to divest generation assets at DENA, primarily in the southeastern U.S., and we are already taking steps to exit DENA's business in Australia.

We expect to complete our exit from Europe in the first half of 2004.

While Duke Energy continues to be subject to significant litigation and regulatory challenges, this is also an area in which we've enjoyed significant successes over the last year.

Highlights include the dismissals of the shareholder class action suits arising out of round trip trading, the settlement of false price reporting allegations with the CFTC, and the Federal Energy and Regulatory Commission staff's exoneration of DENA for allegations of physical withholding during the California energy crisis and the settlement of all California ART related court matters, except for the refund case.

While it's unfortunate that we did not deliver on our earnings goal, reaching and exceeding the other financial goals and clearing up significant legal and regulatory issues should not be overlooked.

The company has made a dramatic shift in capital management. Some of my top priorities include the continuing evaluation of the portfolio from a strategic perspective, ensuring strong capital discipline across the organization and focusing on earning appropriate returns on all of our investments.

My first few months on the job have been oriented toward providing stability by naming a strong leadership team and making key operational and financial decisions.

In doing so, we've streamlined the organization, eliminating the roll of the Chief Administrative Officer, combining finance and risk, combining DENA and DEI into Duke Energy America, under Bobby Evans; and numerous other similar yet significant actions.

A few weeks ago, I laid out high-level goals for Duke Energy. And next week, we will provide you with more detail on our medium term expectations for each of our businesses.

Let me assure you, the entire management team is focused on improving the results you see from Duke Energy and providing superior long-term value for investors. Let me remind you that my entire compensation is based on Duke Energy stock that cannot be sold before 2007.

As such, I'm totally aligned with other long-term investors. With that, let me open the lines to your questions.

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please press star one at this time. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment.

Once again, it is star one if you do have a question. We'll take our first question from Kit Connelage with Morgan Stanley.

Good morning. Thanks for all the detail. Wanted to ask a little bit about DENA.

The implication, I think it was you, David, overall in your discussion as I understand it was that the fourth quarter net of the special charges and so on should start to reflect kind of what can be expected on an ongoing basis.

So what I wanted to ask was, first of all, the $74 million negative EBIT at DENA, how does that vary quarterly going forward, and can you give us an idea -- you talked about the $600 million in low risk gross margin in '03. What would the comparable number be now for '04?

This is Paul. First of all, I guess one of the things that we're going to get out of doing is making a bunch of forecasts and then spending all of our time talking about the numbers. We have told the market that we expect DENA to lose as a base case $300 million.

So, you know, that's sort of our total guidance at this point in time. I'll let David comment on the low risk gross margin.

Yeah. We have talked in the past about low risk gross margin, and we've said it's 300 to slightly over $300 million for 2004, and that's still where we would expect it to be, Kit.

Of course, the drop from this year is because we have less hedges at somewhat lower prices.

I noticed that you have higher production in '05 than '04, now. In fact, my recollection was that it used to be pretty flat. Are you seeing some different expectations now?

Well, in '05, our production -- I don't have the third quarter with me, but in '05, we've actually reduced our estimated production some.

We took out the southeast plants, and we took out the deferred plants in '05.

It's Greg Ebel. The estimated production in the third quarter that we've told you for '04 was about 30 million megawatt hours. Now we're at about 20 million megawatt hours. So it has come down.

I see. Finally, just separate area, can you discuss -- it looked like the tax rate overall in the fourth quarter -- and obviously, there's a lot of things washing back and forth -- was I think we calculated about 24%.

Is there going forward, you know, should we assume a kind of normal corporate tax rate?

Yes. Of course the tax rate when you have positive earnings from some international operations and then the big losses that we record, the tax rate calculation gets fairly meaningless on a consolidated basis.

But if you look going forward, if you looked at the statutory rate of federal about 35 and a couple percent per state, you'd be on track.

Very good. Thank you.

And moving on, we'll take our next question from Dan Eggers with Credit Suisse First Boston.

Good morning.

Good morning, Dan.

Not to belabor DENA too much, but just from a strategic standpoint, y'all are talking about 80% hedged on the gas side of that business.

As you approach, I guess, the company in a more maybe conservative manner, is that hedging position going to go up, and are you planning on locking in those positions in the near future, I guess?

I'm going to turn that over to Fred, because we get that question a lot.

And I think the answer is pretty straightforward. But I'd like him to give it.

Yeah, just to clarify, what David said was in excess of 80%.

Yes.

Okay? That's the first point.

I think the second point is basically, the model that we have, that we use, indicates that you are always a little bit shorter gas than you are your power that you have sold.

We've used that model consistently. We have been through in recent times several pretty big movements, both in all directions on prices, and you will note that we've never had any big hits.

So our model continues to prove out, and work pretty well.

Okay. I guess the other question is, you guys are talking in excess of $200 million of cost savings in '04 over '03.

Can you give a little more color on where all those pieces are coming? I know some is from O&M. But maybe a little more clarity there.

The really big driver, if you look at it since September of '02, we have reduced 4,000 people in this company.

It's the accumulation you get off of not only just, you know, the salaries and benefits of the employees, but employees, you know, there's other costs that go along with them that start going away.

Computers start disappearing as the leases roll off. Office space that you had as leases roll off goes away. So you start seeing the cumulative affect.

And that's really -- that along with procurement-type savings is the major drivers.

Okay. Thanks, guys.

And moving on, we'll take our next question from Andrew Davis of Harvard Management.

Good morning. I'm wondering if you could comment on the recent Moody's release which said "management has reiterated its commitment to maintaining investment grade credit rating through capital. Based on revised metric projections, we anticipate that the parent will need to contribute additional support in 2004".

That runs contrary to what you said in the last conference call. I just wondered if you could comment on where that kicks in.

Well, we're in good communications with both Moody's and S&P and have met with them and reviewed all our plans with them.

No decision has been made about whether any movement of cash from Duke Energy to Duke Capital will need to occur in '04. I think that depends on the timing of all the cash flows in '04.

But keep in mind as you look at '04, that the vast majority of the debt that comes due in '04 is not until the last quarter of the year.

So we don't anticipate having to move any cash from Duke Energy to Duke Capital, but we'll assess as the year goes and make the right decisions.

Thanks.

And moving on, we'll take our next question from Jessica Rutledge of Lazard Asset Management.

Sorry, I was on mute.

I am hoping to follow-up on your comments about Franchised Electric back at the beginning of your presentation, where you talked about the earnings number being consistent with both the rate base and the allowed returns in North and South Carolina.

What are the realized returns at the utility today, and where does your rate base stand?

Our realized returns in South Carolina are at 12 1/4. Our realized returns in North Carolina are slightly above 13. Anybody in the room know the exact number?

At the end of the year, they will be a little below 13.

A little below 13. Okay.

And are those levels where you feel that it is a sustainable projection looking forward, where you just basically sit on those return numbers?

Yeah, I think we're pretty comfortable with those.

That's the allowed number in South Carolina, by the way.

Okay. Excellent.

And also just to follow-up up on Kit's question at the beginning, what was the full year tax rate underlying your operating numbers for this year?

Well, the simple way to look at that is the statutory tax rate is about 37. And to the degree things have happened different than 37, it's because of one-time events.

And so for modeling purposes, you really ought to use a rate of about 37.

So it's fair to assume in the ongoing earnings numbers that you gave us, you assumed a statutory rate of about 37 and everything else went below the line to the extraordinaries?

Well, I'm with you on up to the 37, but I don't know about the part below the line.

Okay, I'm sorry, I think I'm being imprecise from an accounting standpoint.

In our GAAP reconciliations, when you talk about the ongoing earnings number, you are using a statutory tax rate to come up with it.

Yes.

Okay. Thank you.

Okay.

And next we'll go to Maureen Howell with RBC Capital Markets.

Thanks very much. You talk about the debt reduction of 2.2 billion. And I'm just wondering, I realize there's been a re-classification of the preferred securities of about $900 million.

But also, that's basically offset by the classification discontinued of about $880 million, I guess associated with the Australia assets. So when I look at the balance sheet, we really only see a reduction in debt of $500 million.

And in fact, the debt to capital number, you know, increases. Part of that, I guess, would be, you know, foreign exchange translation.

But I'm wondering if you could just reconcile how we go from the $22.5 billion to the 21. -- or almost $22 billion, I guess.

Okay. The difference between the 22465 and the 21952 that we showed on the quarterly highlights, the drop is less than the 2217.

But that is because of the $1 billion due to the FX translation and $9 million due to the re-class of the trust preferreds.

Okay, but that's still -- we're still missing something, right? Because. you know, as I said, that the -- you also have the discontinued $880 million which kind of offsets the 900, right?

Let me see --

I'm assuming the $880 million is not in the $22 billion. I'm assuming that's what that note means?

That is correct. Let me clarify one other thing on the 22. The 22465 did not include the trust preferreds last year.

No. I understand that -- oh, okay. Okay.

I think that may be the difference that you're not picking up.

So in the 2002 number shown here, the trust preferreds are not in there.

That's right. Because when the accounting change occurred, you changed it prospectively.

But on that particular change, you did not have to change it retroactively.

But the Australia numbers have been taken out in both years?

Yes, that is correct.

Okay. Yeah, that explains that.

If I could just get a clarification on a previous clarification. In the $1.28, the tax -- if we had the tax number, the tax calculated would be 37%?

Yes. It's not exactly 37%, because there are a few permanent differences.

But if you're looking at Duke's tax rate, 37% is a good number.

Okay. That's great. Thank you very much.

And next we'll go to Jay Yannello with UBS.

Good morning. If we could look at slide six, the Delta in Franchise Electrical ongoing segment EBIT was, I think, roughly $144 million.

You gave us a little flavor on that. Could we have a little more dollar value, what was weather, what was lower off-system sales, what was the clean air expenditures, and what was other year over year. If you have those comparison,s that would be good. Because 144 is a pretty big number.

Yeah. Starting off you've got higher D&A of 137 million, about 115 of that is the clean air amortization.

We had lower sales due to unfavorable weather of about 70 million. We had the South Carolina rate reduction of 30 million. We had a little bit lower industrial sales of about 13 million.

And then those were offset by higher bulk power marketing sales of 112, and higher residential and commercial customer sales of about 38 million.

Okay. Thank you.

And the second question, can we have the Crescent property sales number for the fourth quarter this year and the fourth quarter last year?

We don't provide that information quarterly, I don't think normally.

Okay. Thank you.

And moving on, we'll take our next question from Michael Goldenberg with Luminous Management.

Good morning, guys.

Good morning.

Good morning, Michael. You're a little weak.

Is it better now?

Oh, it's much better, thank you.

Could you explain the $222 million number in other EBIT?

Maybe you could break it out for us if at all possible.

All right. Let me make sure I'm with you. What slide are you looking at?

Slide four, ongoing segment of EBIT of "other" of $222 million.

The biggest part of that, just the lion's share of that is corporate governance. We don't allocate corporate governance back to the business units. So that's the way you ought to look at that.

So what percentage of the 200 plus is corporate O&M?

It's the vast majority.

Okay. And on the Franchise Electric, if I back out the one-time items and I use the $1.5 billion EBIT versus one four, what is the ROE we're looking at then -- or approximately ROE we'd be getting if we used the one five number, versus the one four reported?

We haven't calculated that. Fred provided the returns based on the reported EBIT.

Okay. Just one final question on the debt maturities, 4.8 billion. There's obviously a big chunk of the mandatory converge.

The other portion, have you guys identified what specifically you can re-pay? Because I'm not sure I'm getting that number with current maturities. So maybe you will be buying back some stuff earlier.

Just wondering if you guys have identified what particular you can pay off early.

Well, we certainly have a list of that. But as I said, it is all of the callable debt.

And the big pieces of that would be the trust preferred securities and a project financing we have with one of the banks that's about a billion dollars, as well as one set of retail notes that becomes callable.

Okay. But all of these have actually been identified?

Yes.

You can look in our supplemental information, and you can see what is callable, if you look at the supplemental filing we did at the end of last year.

Uh-huh.

And that would tell you what the callable debt is.

Great. Thank you very much, guys.

Okay.

And we'll take our next question from Leslie Rich of Bank of America.

Yeah. Yeah, I wondered if you could clarify the goodwill on the balance sheet.

During 2003, you impaired $250 million or so of goodwill, yet the goodwill balance increased. And I just wondered what that goodwill is mostly attributable to? Is it all West Coast or is there some other pieces in there?

I think the big movement you're seeing in goodwill that you're talking about relates to FX, because you have to move goodwill with FX as the currency changes.

And that applies to Canada as the big driver there. It is West Coast.

Okay. And then just to clarify in terms of cost savings, the $200 million, is that incremental 2004 over 2003, or that's sort of cumulative since you began your cost initiative?

No, that's incremental 2004 over 2003.

Great. Thank you.

And moving on, we'll take our next question from Glenwyn Chan of [INAUDIBLE].

Good morning.

Most of my questions have been answered, but I was wondering if you could comment on timing of any announcement of the sale of the southeast plants?

We will announce them just as soon as we have a disclosable event.

Okay. But definitely it's an '04 event?

Certainly our goal and both Fred Fowler and Jim [INAUDIBLE]'s bonuses are based on accomplishing those in 2004.

Okay. Thanks a lot.

And moving on, we'll take our next question from Brian Chin of Smith Barney.

Hi. If we could just circle back to the rate-based question on Franchised Electric, what the rate base is as of the end?

What's the question?

The question was what was the rate base for Franchised Electric, if you could just kind of center us in terms of the end of the year.

That number is -- of course it moves around a little bit, but it's between 8 and $9 billion.

Thank you.

And moving on, we'll take our next question from Jason West of Deutsche Bank.

Hi. A couple of questions.

One, if we wanted to calculate just the net income from Franchised Electric, could we do that by taking the EBIT and then subtracting all the interest expense associated with the DUK debt, you know, Duke Energy only debt, and then, you know, put a tax rate on that? I mean, is that a proper way to calculate net income for the utility?

That would come pretty close. I think you'd have to make some AFUDC adjustments that wouldn't be reflected in EBIT. But other than that, that would bring you pretty close.

I guess my advice would be wait until we file the Duke Energy and Duke Capital 10K's and go look at the differences.

Okay.

And then the other thing, I know this has come up a couple of times already on the call, but just trying to get the number that you guys use for the tax rate in '03 in doing your operating numbers. And I know the forward looking is obviously more important, but looking sort of '03 actuals is also important, I believe.

And I was just wondering what you guys use there.

I guess I'm not clear how to answer the question, other than what I have answered.

We use the statutory federal tax rate, and then there are some items such as amortization of ITC and some ESOP dividend distributions that are some permanent differences that impact that. And then of course, the fact that you have some losses and some foreign earnings impact it.

But again, I would be focused on using about a 37% rate going forward.

All right. Thanks a lot.

And we'll take our next question from Ollie Auga with Burnham Securities.

Thank you.

First question, the gas that you have hedged '04 through '06, could you give us a sense of what price that's been hedged at? You gave us the power side, but could you also give us the gas side?

No. That's information that we don't disclose.

Okay. Fair enough.

Separate question. Could you tell us how much of an impact was the Brazilian currency -- strengthening of the currency -- in the fourth quarter to the internal results?

In Brazil, we have the investment, and then we have substantial debt in Brazil, around $400 million of debt in Brazil. And that debt is in re-ice.

So the movement of currency in Brazil is not a very important factor for us. So the currency in the fourth quarter in Brazil was not significant to earnings at all.

Okay. And finally, just wanted to clarify another point. When you gave us your DENA production numbers, '04 through '06, you've taken out the southeast and deferred plants.

Specifically as it relates to the southeast, are you including that in those in your outlook for '04, or should we expect that they will be discontinued at an early stage this year?

They become discontinued operations at the time we actually have a sales contract on them.

And moving on, we'll take our next question from Vic Tapan with Deutsche Asset Management.

Thank you. Yes. One follow-up question on this southeast asset sales.

While intention is to do it as soon as possible, but given the [INAUDIBLE] recent issue about looking at these asset sales to utilities or where there may be some competitive issues, so do you see that could be somewhat of a challenge, or do you think that you have sufficient by as to make that thing work?

I think there's no doubt that will complicate it. Some of the logical buyers are incumbent utilities, there is no doubt about it.

And it looks to be -- it's our feeling that it's going to make that a more difficult transaction to get closed. So we'll have to see.

But to me it makes it probably more -- it's probably more probable that we'll be looking probably at financial buyers as opposed to incumbent utilities, until we start getting a better feel for what this order really means.

So does that mean that the asset sale could be slowed, or you think that you can still accomplish it within your time period?

Yeah, I don't think it has any -- I don't think it will necessarily slow it down. I think it will just provide a smaller potential buyer base.

And the other thing which I'm not sure whether you provided today or not, but the earnings potential for this company, I mean, do you have a long-term view as well as a short-term view?

So is that something which you'll discuss later on or are you willing to discuss today also?

Well, what we've said at our call on the 7th is that we've set the target for management incentive purposes at $1.20 for the target -- $1.20 per share for the bonus target. Beyond that, we are not planning to provide guidance in any great detail.

Next week, we'll be giving some outlooks for individual operations for the medium term. But I don't intend to say, you know, earnings will be in a range of X to Y and then spend the rest of the year refining that and defending penny movements off that.

No. I understand that, Paul.

But given your long-term commitment of the share value, you probably have an idea about what this company can potentially do, so that's what we are trying to understand, what are the potential there?

Sure. Well, we've said that our goal is for income and modest growth.

And, you know, to start defining it precisely, it would just get ourselves in that trap where you get stampeded into putting out numbers and defending them. You know, modest growth is probably in the 4 to 6% range. So, you know, that's what we're looking at.

As a base going forward, obviously we're going to be trying to improve on that. But I don't want to start defining all kinds of forecasts out there and then, you know, spending our life defending them.

I understand the challenge. Thank you so much.

Thank you.

And we'll take our next question from Devon Bogan with [INAUDIBLE] Lucas Partners.

Hi. Just one question.

Next week will you guys give EBIT guidance by segments? You typically have not given it for other, but you've given it for the four major segments.

What item?

EBIT guidance by segment.

No. I mean, we'll give guidance as to, are things going to get better or worse.

But as far as saying -- other than the one number we have given you, which is --

For DENA.

For DENA, the $300 million loss. But we'll just give sort of trend indications. But we're not going to try to put numbers out there.

Okay. So that makes sense.

Thank you very much.

And we'll take our final question today from Steve Flieshman with Merrill Lynch.

Yeah, hi, good morning. I'm not sure if you have this number, but in 2003, the DENA business -- is it possible to provide any sense of what the southeast plants did in 2003?

Or if you can't specifically do that, some sense of the, you know, loss of 75 million of EBIT roughly, how the different regions may have performed with that?

At this point, we have elected not to give regional information for DENA. So I don't think we're going to start down that path right now, Steve.

Okay. Thank you.

And that concludes today's question-and-answer session. Mr. Ebel, I'll turn the conference back over to you for any additional or closing remarks.

Thanks, Paula. Just to say thank you to all of you for your time today. And of course, the team is ready to take your questions throughout the day and help you through the numbers.

Thank you very much, and we'll see many of you next week in New York.

And that does conclude today's conference. We do thank you for your participation. At this time, you may now disconnect.