Duke Energy Corp (DUK) 2002 Q4 法說會逐字稿

Good day, everyone and welcome to today's Duke Energy first quarter 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 Eibel (ph). Please go ahead, sir.

Thank you. Good morning and thank you all for joining us today.

With us today is Rick Priory, chairman and CEO of Duke Energy; Fred Fowler, president and COO; and Robert Brace, executive vice president and CFO.

Today we'll provide you with an overview of Duke Energy's earnings for the fourth quarter and give you some supplementary information on our trading activities. We will also provide you with more detail on our earnings guidance for 2003. Today's call is being webcast on our webcast at www.duke-energy.com, and a copy of the slides will be available for downloading in the investor section of our website.

Before we begin, I'll quickly review our Safe Harbor statement. Some of the things that we will discuss today call on the future company performance will be forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in the forward-looking statements and you should refer to the additional information contained in our SEC filing concerning factors that could cause those results to differ from those contemplated in today's discussion.

We will begin today's call with some prepared remarks from Mr. Priory and Mr. Brace, and then open the lines to take your questions.

Well, good morning, this is Rick Priory.

Let me begin by saying how very happy I am that the year 2002 is now behind us. It really was a tough year for Duke Energy and not to mention our industry. There were many unusual events, but clearly the precipitous decline of the U.S. merchant markets and the very difficult credit conditions that our industry faced certainly created major and significant problems. For a business that performed so well in 2001 -- perhaps our historically greatest year in terms of delivering to shareholders -- our Merchant Energy business, Duke Energy North America learned some hard lessons in 2002. Clearly, those lessons were about the business itself as well as the impact that external events can have on an ongoing business in a free market.

We confirmed a lesson that we really already knew, the importance of remaining an integrated and a diversified business. Even as the merchant sector virtually collapsed this year, our franchise electric and our natural gas transmission businesses remain robust. Those businesses delivered really the vast majority of our earnings in 2002, nearly $2.8 billion of earnings before interest and taxes. Meanwhile, our merchant energy businesses struggled throughout the year with a dramatic decline in trading and marketing liquidity and oversupply of merchant generation, low commodity pricing and volatility, and frankly, below par performance from our international business.

We reported earnings for 2002 of $1.22 per-share compared to $2.45 per-share in 2001. Included in our reported results for 2002 is a relatively long list of charges totaling about 66 cents, which can be primarily attributed to the effects of changing market conditions, severe weather, and also the necessity to reduce our workforce in recognition of the market realities that we face in 2002, as well as what we anticipate facing beyond that into '03. Excluding those charges, results from ongoing operations were $1.88 per-share in 2002 compared with about $2.64 in 2001.

The good news for 2002 really was the successful integration of West Coast Energy, which contributed ten months of earnings to our natural gas transmission business, and the exceptional performance of our nuclear facilities which reported this year record capacity utilization of 95% both for the fourth quarter and also for the year in total. Additionally, our aggressive actions to reduce capital spend made excellent progress this year as we finished the year with cap-ex spending $200 million less than our original guidance to you of $5.8 billion. So we finished the year with $5.6 billion in terms of cap-ex.

Duke Energy reported a quarterly loss of six cents per-share for the first quarter of 2002. Earnings per-share for the fourth quarter of 2001 were 29 cents. Excluding charges for goodwill and asset impairments, the storm cross which we all know about, the severance related to reducing the workforce and the Duke Power settlement with utilities commissions and the write off of an IT system, ongoing earnings for the fourth quarter were 32 cents per-share.

Robert will provide more detail during the business unit discussions on the specifics of each of these charges. Reported earnings per-share for the fourth quarter of 2001 were 29 cents per-share, with 35 cents per-share excluding three cents in charges related to Enron's bankruptcy and also a three-cent charge at franchise electric for a change in methodology for calculating unbilled revenues. So in summary, virtually all of the significant reduction in earnings for the year could be attributed to our Merchant Energy business in the United States. Although we're not satisfied with the performance of our field services business or international either, there is no doubt that the U.S. energy merchant business dominated the down-side this year.

In times like these we really do appreciate the solid and very substantial earnings in cash flow contributions from our franchise electric and our gas transmission business.

And with that, let me turn it over to Robert for the detailed explanation in each of the business units -- Robert.

Thank you, Rick.

First of all, I would like to start with the natural gas transmission, which delivered the largest portion of earnings for the quarter. Our gas transmission businesses in the United States and Canada delivered $307 million in EBIT for the fourth quarter of 2002 compared with $148 million in the same period in 2001. The primary driver for the dramatic increase was the contribution from our West Coast businesses, which delivered $154 million in EBIT in the quarter and a total of $416 million during the year. Incremental earnings from business expansion projects such as connecting the new gas-fired power plants as well as storage expansion projects also contributed to higher earnings for the quarter. Included in the strong results in our pipeline operations were severance charges totaling approximately $9 million. The next largest source of earnings for the quarter was franchised electric, which reported EBIT of $249 million compared with $203 million for the same period in 2001. Franchise Electric had an eventful quarter.

Weather had both a positive and negative effect on earnings for the quarter. We saw heating degree hours increase more than 20% over last year's fourth quarter. This colder weather increased gigawatt (ph) hour sales by more than 17% year on year. Not surprisingly, residential and commercial sales led the increase with 17.8% in 6.1% growth respectively. However, industrial sales did not benefit during this quarter and showed a slight decline in sales of .7%. The number of customers increased by 1.5% during the first quarter.

The down side of this cold weather in the Carolinas was the ice storm in early December. The charges associated with replacing the equipment and restoring electric service to about 1.4 million customers totaled $89 million. Also during the quarter, franchise electric recorded a $19 million charge related to a settlement with the utility commission in North Carolina and South Carolina, and recorded another $14 million in charges related to workforce reductions.

Fuel Services reported EBIT of $27 million during the quarter, which included an asset impairment charge of $28 million. These impairments are related to pipelines we are abandoning or are near abandonment, and a few processing plants and gathering systems which have performed marginally well. Results for the quarter benefited from the increase in NGL prices but were partially offset by an increase in natural gas prices. Weighted average NGL prices improved over the quarter, averaging 45 cents compared to 31 cents last year. Partially offset in the positive impact of fiber blend NGL prices were higher O&M expenses primarily related to pipeline and compressor maintenance.

While prices for the fourth quarter showed dramatic improvement, weighted average NGL prices for the full year were lower in 2002, 38 cents, when compared with the 45 cents in 2001. During the fourth quarter, Fuel Services completed its ordered review and balance sheet clean up. It took a charge of $7 million related to the final cleanup. Fuel Services have spent significant time, money and resources on improving its internal controls and addressing these problems, and does not anticipate more charges related to these matters.

Duke Energy North America's results for the quarter continued to reflect the poor market conditions for the Merchant Energy business. Continued downward pressure on spark spreads and low volatility severely limited our ability to create value in the marketplace. DENA reported fourth quarter EBIT of $22 million compared with $177 million last year. Earnings for the quarter were negatively affected by reduced earnings from proprietary trading and by lower earnings from origination due in part to the required change from market to market to an accrual based accounting in late October.

In addition, DENA had increased depreciation expenses associated with the new generation facility that began commercial operation in the summer. During the fourth quarter, DENA had additional charges for workforce reductions of $7 million and demobilization costs of ten million dollars. DENA also incurred charges of $24 million in the fourth quarter for an information management system write-off.

Duke Energy International's operations reported an EBIT loss in the fourth quarter of $211 million, including a $194 million charge for goodwill impairment and a $4 million charge for severance costs. Excluding these charges, ongoing EBIT was a loss of $13 million. Ongoing EBIT for the fourth quarter of 2001 was $71 million and that excluded a $3 million charge related to Enron's bankruptcy.

The primary reason for the adverse EBIT there in the prior year during the fourth quarter was the goodwill impairment charge related to our European gas trading business, Megas (ph). Market conditions in Europe have declined dramatically over the last year and in particular in the last quarter of this year. This reduction in goodwill is a direct result of the company's negative market outlook for the European natural gas trading market. Other factors contributing to the adverse fourth quarter variance and DEI's EBIT include losses in Europe related in part to difficult market conditions and the company's decision to exit power trading in Europe, as well as weak performance in Brazil.

In addition, last year's fourth quarter benefited from a resolution of the water rationing program in Brazil and during the first quarter 2002, we also set up a reserve for potential and collective receivables of approximately $13 million in Brazil. DEI also increased by $22 million its reserves associated with non-performance by its supplier and an LNG (ph) gas supply contract that is currently in arbitration. This addition was -- takes into account the significant increase in the price of natural gas over the last quarter.

For all of 2002, Duke Energy reported total segment EBIT of more than $2.8 billion compared with total segment EBIT of $4 billion in 2001. Franchise Electric provided its usual steady earnings year-over-year and EBIT financial gas transmission benefited from ten months of the earnings from West Coast, as well as incremental earnings from business expansion projects. As in the year 2002, these two major regulated operations are expected to contribute the majority of Duke Energy's earnings and cash flow in 2003.

DENA reported a reduction in full year EBIT of $1.3 billion including $247 million of special charges. On an ongoing basis, excluding these charges, DENA's EBIT was down $1.1 billion, or the equivalent of about 82 cents per-share.

Next, I'd like to briefly review Duke Energy's liquidity position.

For those of you who participated in our call a couple of weeks ago, this will be a repeat of some of that information. But given the importance of liquidity these days, I hope you will forgive me. Liquidity for the corporation is managed in a centralized manner. Duke Capital provides funding for all entities except Franchise Electric, West Coast, Union Gas and Fuel Services. As far as our credit facilities are concerned, Duke Energy maintains credit facilities of $950 million at Duke Energy to fully backstop its CP program. Duke Capital has credit facilities of $2.9 billion of which approximately $1.6 billion fully backstops its CP program. And there are no rating triggers on the credit facility supported in the CP programs at Duke Energy nor of Duke Capital.

Total credit capacity for the corporation is about $5.6 billion of which approximately $2.7 billion was outstanding at the 31st of December, 2002. Our unused capacity as of December 31 was approximately $2.9 billion in addition to cash on hand of approximately $850 million.

Let me talk about collateral and the effects of credit rating movements. Most of our trading is conducted through Duke Energy Trading and Marketing, which is currently rated BBB plus by Standard and Poor's. A one notch downgrade of DETM would require an estimated $40 million of additional collateral to be posted by Duke Energy. A further one notch downgrade of DETM to BBB minus would necessitate additional collateral from Duke Energy again of around $40 million, so that is $80 million in aggregate.

If I could move on to our trading disclosures. In respect to the trading portfolios, the evaluation of our accrual book as of the 31st of December, 2002, was $5.2 billion in gross margin. Our market to market book was valid at $9.4 billion. The accrual portfolio includes the value of the hedged positions, the expected value of any unhedged generation over a nine year period as well as normal purchases and sales contracts. Although these types of contracts are not recorded on the balance sheet, the gross margin from these contracts is recorded in the period in which the physical delivery takes place. The reduction in the market to market portfolio from the last quarter was primarily due to settlements during the quarter and a reduction in the portfolio evaluation due to market changes.

The required change in accounting treatment for certain origination contracts to an accrual base after October 25, 2002, also had a small negative impact on the market to market portfolio. The average daily earnings at-risk for Duke Energy in the fourth quarter of 2002 was $11 million and that compared with an average of $12 million for the same period last year. We have published additional and we hope you will agree improved trading disclosures for DENA as we start to conform our disclosures to those recommended by the committee of chief risk offices.

Today we are providing more detailed information on the hedging related to our Merchant power plants. To begin with, our estimate of the total production available in our U.S. Merchant plants for the whole of the year of 2003 is approximately 89 million-megawatt hours. This number takes into account our expectations for normal maintenance. Of the total available production, 79% is from our combined cycle plant and 21% is from our peaking units. Our expected production from these plants is currently 28 million-megawatt hours, of which 27 million-megawatt hours is planned to come from our combined cycle plants and about 1 million from our peaking units. As of December 31, we had hedged 102% of this expected power output for 2003 at an average price of $51 per megawatt hour.

We have additional information included on the disclosure sheet that went out this morning and is also posted on our website.

Let me move on to 2003 earnings guidance. For those of you who may have missed our call earlier in the month I will briefly review that guidance and provide some additional information for Fuel Services and international energy. First, the earnings per-share guidance, first the earnings per-share guidance. It is $1.35 to $1.60 per-share for 2003 and our budget would put us at the upper end of that range. This range excludes the one time charges we expect to take in the first quarter of '03 for the implementation of VITFO 203 and FAS 143. These after-tax charges -- these charges are likely to be between two and $300 million before tax, although there are still some issues that require clarification for the accounting profession before we can completely finalize these amounts.

Our regulated businesses, Franchise Electric and natural gas transmission will be the largest contributors to earnings in 2003 delivering approximately 80% of total earnings before interest and tax. Franchise Electric is expected to deliver approximately $1.6 billion of EBIT in 2003. Expected kilowatt hours sales growth of about 1.8% will be offset, we believe, by increased amortization expense related to the North Carolina clean air legislation passed last summer. The five-year rate freeze approved alongside this same legislation begins in 2003.

EBIT for natural gas transmission is expected to be approximately $1.2 billion. West Coast will contribute its first full year of earnings and an expansion project such as the hub line (ph) and maritimes (ph) extensions will also add incremental earnings during the year. Fuel Services' EBIT is expected to be approximately $200 million in 2003. Average NGL prices are expected to be higher in 2003 than in 2002, but we do not expect to see significant changes in volume through the system due to the lack of new drilling activity.

Duke Energy North America is expected to deliver approximately $200 million in EBIT. Generation oversupply, low spark space and low volatility as well as any lack of meaningful signs of economic recovery all point to another tough year for DENA. Duke Energy International is expected to improve its earnings in 2003 with EBIT expectations of around $250 million. In response to current market conditions, we have reduced our European trading operations and halted our development efforts. The Asia Pacific and Latin American regional businesses are expected to be our strongest earnings contributors in this segment.

Lastly, we expect interest expense to be between $1.3 and $1.4 billion in 2003. With that, let me turn back to Rick who will wrap up our prepared remarks.

Thanks, Robert.

In developing our plans for 2003, it identifies a whole range of challenges you might imagine facing Duke Energy, facing our industry and also our nation. Our primary concerns are the pace of economic recovery, obviously the substantial imbalance between supply and demand for electricity, and the regulatory and legal uncertainties that are facing our industry. All of the industry signals that we watch, supply and demand, spark spreads, volatility, credit conditions and liquidity simply point to another challenging year in 2003.

In response to these current challenges, Duke is really focusing very sharply on reducing risks and restructuring our business for future success. We have six key goals for 2003 -- number one, focus on positive net cash generation; number two, invest in our strongest business sectors; number three, right size businesses to the market realities that we face; four, address Merchant Energy issues; five, strengthen our relationship with customers; and six, reduce regulatory and legal risk and its associated uncertainty.

Our watchword in 2003 is discipline. We will focus on cash generation and capital management, we'll limit discretionary spending and reduce our debt. We have cut capital expenditures by more than a half to $3.2 billion in 2003. We expect cash from operations and asset sales will fund our capital expenditures and our dividends, and also reduce the need for any outside financing. We'll have about $1.3 billion in debt that matures in 2003 of which we expect to refinance a portion of that and pay down the balance.

For 77 consecutive years we have paid quarterly dividends on our common stock, and our plans for 2003 fully support the dividend at its current level. All the board of directors has the final decision on dividend policy. They have approved the 2003 plan which includes dividends at the current level of $1.10 per-share. We're committed to strengthening our balance sheet and our cash position, and we'll continue to divest assets when we can capture value and enhance near-term liquidity.

We will continue to invest in our strongest businesses to create long-term shareholder value, and across all businesses I have directed my team to sweat our assets to improve returns on capital like we have never done before. We're reducing our workforce by about 2000 employees -- that's about 10% of our workforce -- as we restructure our businesses to accommodate market changes and also to capture additional efficiencies. This reduction should provide savings in excess of $150 million per year. And we have realigned and substantially reduced our Merchant Energy organization as it relates to new power plant development and construction and energy trading.

We continue to view the energy sales and marketing business as a vital component of a healthy wholesale energy market, but we're focusing on energy sales and marketing around our asset positions and have positioned proprietary trading to be a very, very small part of our overall business. While we have reduced our merchant business overall, we're working to build our physical market share and to increase sales with wholesale customers. Forging new customer relationships and enhancing existing ones has clearly been the core strength of our company over many years. And certainly one of my challenges for 2003 will be to work with industry leaders, regulators and legislators to promote a healthy energy sector for years to come and hopefully to bring about some of the stability which will allow then the market to become efficient and functioning again.

We're taking the tough steps during this market down-turn to assure that we'll be well-positioned for the inevitable return. We have responded to these turbulent times. We have drawn upon the very key strengths that define us at Duke Energy, portfolio strength, financial strength and management debt.

So now let's go ahead and open the lines, and we'd be delighted to take your questions.

Thank you. The Q&A session will be conducted electronically today. If you would like to ask a question, please press star one on your telephone. Again, that is star one if you do have a question today.

And we'll go first Andrei Mead (ph) at Bizard (ph).

Hello, Andrei.

Hi. How are you?

Good.

Two questions. One, I just want to talk about Duke Capital's balance sheet and then a bit on DEFS. For -- you spoke about cutting cap-ex enough to fund so OCF can cover cap-ex plus dividend. Seems to me that you need to go beyond that significantly to delever Duke Capital, and if my math is correct, you're about -- you were about 60% debt to cap there. You add about $500 million in write-downs which is the Duke Capital portion of Q4 write down plus what you're going to see in '03. It doesn't look like you did any or had any impairment charges for your merchant plants, but it seems pretty obvious to me and probably to you, too, that they're not worth construction costs on the balance sheet. So I guess my question is two things -- one, when do you expect S&P to act? When do you think Moody's will again review you? After they have downgraded in December and then what --seems like you might have to look at some big ticket items for sale and I was wondering if you're very committed to your -- the Western pipelines you have got with West Coast being Alliance, Foothills and BC Pipe (ph), might you think about selling those?

Andrei, we will start with Fred Fowler addressing both your questions and your comments.

Hello, Andrei. First of all, with regard to S&P, we are in ongoing dialogue with all the rating agencies and of course, they -- S&P has its own negative outlook and has had since October the 4th. Their decision of what actions they will take is totally up to them and we simply do not know if and when they will elect to take any action on Duke Energy or Duke Capital. But we have provided them all the current information and do have a running dialogue with them. Moody's, of course, acted on December 23rd and took some ratings actions that we have announced before and left us on negative outlook. We don't have any reason to believe that Moody's is looking at any further action at this point.

With regard to Duke Capital, you've quoted some numbers. We would expect that the Duke Capital balance sheet will get stronger during the year, 2003. We would expect that we'll have some debt maturities at Duke Capital in 2003 and we will not have to issue as much debt at Duke Capital as is retired at Duke Capital. My numbers at Duke Capital at the end of December indicate 54% long-term debt and -- so they're a little different from yours, but if you want to chase that with me we'll be happy to talk off-line about that.

Okay. And what about -

He asked also a question about the pipeline?

Right.

Let Fred address that.

Hi, Andrei. This is Fred Fowler. We do have a process in the company where we value each of the assets and each of our business units. I would tell you that the Western systems would be fairly low on our disposal pecking order. We see that as a key system really well-positioned for future growth. So that would be probably one of the later things that we would be willing to turn loose of.

Okay. Maybe you could tell me what would be on the top of the list as far as the pipes go?

I mean, some of the minority owned pipes in the East or what?

Andrei, you put us in a very difficult position to prioritize the assets that we would bring to market. I mean, the fact of the matter is, we have no intention of bringing to market any of our strategic pipelines and have no need to do so. We do have a number of pipelines that are very non-strategic such as the Empire pipeline you saw us come to market with. But, you know, Andrei, we cannot disclose the priority of those pipelines for obvious competitive reasons. Just like you would like to get the highest price we could for anything we sell in that marketplace.

Right. Okay. DEFS, there is a huge increase in O&M this year as you went through this audit, put in new accounting systems, write-off, various write-downs of receivables and if you look at the total increase in O&M through the year, it was about $130 million or so, and going into next year now that this audit is done, I would have expected the bulk of that to go away. And you earned about, you know, $126 million in '02 on an EBIT basis. So that tells me you would be more like 250 or so rather than 200. What else is going on at the FAS to make your assumptions for 2003 EBIT so low?

Well, Andrei, implicit in that you must have made some assumptions with regard to commodity prices. There may well be a difference between you and us on that no question. Let me ask Fred to address the issues that occurred in'02 which we truly do not expect to occur in '03.

Yes, if you really look at it, Andrei, between the balance sheet write offs we had and the asset impairments, that was about $80 million of write downs this year at the Duke level that we would not expect to reoccur next year. We did have a fairly high OM year this year as a result primarily of a couple of things, two or three things really -- one was the effort that we had on really getting our financial control systems in place. Kind of this year I would classify them more as defect -- as detective type controls. Next year we will continue to spend money on really enhancing automated IP systems on an ongoing basis for better financial controls. We also saw some additional integrity in pipeline work as a result some of new rules by DOT. And then the third thing that we did on the expense side was, because of the low margins this year, we advanced quite a bit of our maintenance type work to get it done during a period when you were not running the plants that hard anyway due to the economics. So that is kind of the essence of what happened this year. Again, you take that stuff, the one times out, the price deck that we're using, that is the number that we come up with.

Thank you, Andrei.

And we'll move on to Thomas Giavene (ph) at Giavene Capital Group.

Mr. Giavene, did you have a question, sir?

And hearing no response, we'll go to Zach Schriber (ph) at Dukane (ph) Capital.

Hi, it's Zach Schriber.

Hey, Zach.

Hi. Rick, I just wanted to -- a quick question just on the last page of the release. First of all, the added disclosure is much appreciated. I was just wondering in terms of if you had the same information that you provided for power on the percent hedges and the average price hedge, if you had that same information for natural gas so that we can sort of back into an average real life spark spread at least on the hedge portion and then project our unhedged spark spread for the unhedged?

Yep.

I mean, we -- you know, we have published this extra information. We have not published the gas prices, but what we have said before is that we are substantially hedged on the gas side. I think you can make a reasonable assessment of what you think our gross margin would be at DENA. I mean, the way that we look at it is we'd say that we have between five and $600 million of fairly secure gross margin for DENA in 2003, which includes the gross margin that would come from, you know, those hedged assets and a few other smaller amounts of revenue that we consider to be low risk. So, you know, including those small amounts of low risk revenue, we have about $600 million of gross margin secured for 2003, if that helps you.

And what is the fixed sort of O&M and D&A at DENA in '03?

The run rate of fixed cost at DENA is around $850 million. So to create a $200 million EBIT, you need just over a billion dollars of income at a gross margin level, and we have at this stage, we have about $600 million which we would consider secured.

Got it. And just -

Let me make sure we're clear on that, because that has been a real bone of contention in terms of getting information out and around. The -- all Robert has spoken about was the hedge value, if you will. Remember, of course, that we have an entire book of an infrastructure of gas pipeline transportation, as well as storage facilities which is a contributor to DENA as no one seems to be asking about these days, but it is a major contributor to DENA's earnings. Likewise, we have as you can see from this disclosure table, a substantial amount of option value in our plant, because of the supply and demand mix that we will be attempting to monetize throughout the year, and we think that will contribute substantial value this year as well as it's contributed in every year historically for that business. We also have the opportunity to arbitrage our book.

We have a very sizable book across the nation, stretching from western Canada to the Gulf Coast to New England and eastern Canada, and that book contains transportation positions, storage positions, power positions, transmission positions for electricity, et cetera. And there are a considerable number of arbitrage opportunities that present themselves in any given year in the ebbs and flows in market, and likewise, we have a very small but nonetheless it has been meaningful over the years, a proprietary trading effort. Again, smaller this year probably than ever, primarily because of liquidity tightening up in the marketplace, and what have you. But you start adding together all those contributors to revenue and that really makes up the difference from where we're going in terms of our gross margin hedged, subtracting out the cost of operation, adding back in then the revenues from this part of the business.

Okay. But just as far as the $600 million, what I ought to do is I ought to effectively by just sort of back solving for the gas price, back solve those megawatt hours to get to the $600 million and that way I can effectively look at -

Zach, I don't know what you ought to do. But if I were you, I would probably be able to run those numbers.

Got it. Okay. Fair enough.

Second question is on the billion three to billion four of interest expense, I think there was some change in the allocation of minority interest expense and I was just wondering if that billion three to billion four fully encompasses all the minority interest expense.

Yes, it does. We had a project financing that we shifted up to debt. That was about a billion dollar project financing and so that is now classified as interest expense and that is in the numbers that Robert gave you for 2003.

Fluor was a fairly complicated transaction and I think our investors will appreciate our having made the effort to smooth that out and make it a very, very simple transaction at this point in time -- it's just dead on the balance sheet.

Thanks, Zach.

And we'll go next to Teren Miller (ph) at UBS Warburg.

Yes. Just a couple of factual questions. What is your anticipated DDNA in 2003 and can you split the interest expense, the $1.3 to $1.4 billion between the Duke Capital side and the Duke Energy side?

I'm sure we can and we're sorting through the paperwork at the present time.

Well, I mean, I'm not sure I can do it at this minute on the call. I mean, we have prepared to talk to you about it afterwards. I just don't have that figure in my head.

The depreciation is $1.9 billion.

A round number and the -- do you have the split of the interest between Duke Capital?

I do not have it with me. I'll be happy to deal with that after the call.

I'm sorry, we just don't have a sheet that would split that out for us nice and easy in this room. Thank you.

And when you said that you could possibly pay down some debt at Duke Capital, can you give us some estimation of what you think that debt retirement could be in 2003?

Well, there are several variables in there, but I think it's safe to assume that would be several hundred million dollars of debt that is retired at Duke Capital that is not replaced.

That is one of my main objectives for this year is to pay down a substantial amount of capital debt.

Thank you.

And we'll move next to Lesley Rich (ph) at Banc of America.

Hi, there. I wondered if you could go through your projections for international earnings in '03 seeing that Europe is not going to be a big contributor, if you could give a little more flavor in terms of why you expect such robust results in '03.

Okay. Lesley, let me turn to Fred Fowler.

Yes, Lesley, I wouldn't exactly call them robust, maybe only in comparison to this year. But I think if you start out this year and you take the two big one time write offs we had, the MEE gas impairment of 193 and the $91 million in the third quarter for the turbine write-offs, and not expecting that to reoccur next year, that adds quite a bit back on to this number. I think from the standpoint of Europe, quite frankly, our trading results in Europe had been pretty bad on the electric power side. That is why we shut it down, so that is another negative that will go away. I think we continue to see Europe as not providing a lot of earnings, although I think it will do okay just if we just focus on our gas positions so we'll take that from a negative to a positive. We continue to see a little additional pressure in Brazil next year, so we see a little bit of probably a down tick there. Actually, we see holding our own and improving only slightly in the northern Latin America and then we see Asia Pacific performing well next year.

We do have some of the new Tazmanian pipeline coming on and we have a very active program to start filling that system up as well as the eastern pipeline. So we just think it is a combination of getting some of these things -- the bad things behind us, focusing on organic growth and further cost reductions. By the way, we did reduce - we had a headcount reduction of about 15% in international this year. We think by continuing to drive cost, continuing to focus on organic growth of our assets next year is going to be an okay year.

Okay. And then separately on the cash-flow statement, you've put a line item "changes in working capital and other" and I just wondered how much of that was actually attributable to working capital?

We're sorting through the paperwork at the present time.

Which cash-flow schedule are you referring to?

For the year. You have one on page 17.

So you're looking at changes in working capital and other for '02 which is $1.9 billion?

Yes. I'm just wondering how much of that was working capital related?

Well, I mean, I think the majority of it is -- I think the majority of it is changes in working capital, yes.

Thank you.

And we'll move on to Paul Dabasse (ph) at Value Line.

Hi. Now that you're going to have West Coast for a full year, what kind of seasonality do you have for your overall company?

Well, in general terms, as you know, let's just talk about the two major parts of the company, the electric business seasonality, as it really focuses on a big third quarter, we have a first quarter contributor, shoulder quarter, then a strong quarter in the third, and then hopefully pick up a little in the fourth quarter. But the big time is the third quarter, in case of our gas transmission business is pretty much the first now with the combination of West Coast and the rest of the pipeline system, it's pretty much a first quarter and fourth quarter phenomenon in terms of seasonality.

So in a normal year the second quarter would be the weakest?

Yes, ordinarily it would be the weakest, correct.

Okay, thank you.

And we'll go next to Wen-Win Chin (ph) at ABN Amro.

Hi. I was also wondering about the $1.9 billion in working capital. Why is it so large this year and do you expect it to be this large in 2003?

Well, in 2002, a lot of the change in working capital relates to the trading and marketing business which, you know, in 2001 and 2002 was quite a big change in -- over that period. I think sort of basic assumptions for 2003, the working capital should be about flat. I mean, the business isn't growing tremendously in any particular area. We're managing our assets so tightly so, you know, I can't be specific, you know, to a few hundred million dollars but we're not looking for a massive change in working capital year on year from '03.

Can you just remind me what your operating cash flow is expected to be this year?

For '03, the way that we have looked at it, the way that we have explained it is we say that, you know, we think we'll generate from -- you know, you can pick your EPS book, you say $1.4 billion or so from our net income. We have $1.9 billion of depreciation and amortization that is non-cash. We have the net book value of present asset sales, which we think you need to add in to get sort of a gross cash number. And then we have got some other cash that we believe will come from sales of other assets and we think we get to about $4.4, $4.5 billion without issuing new equity per se from the dividend reinvestment plans, et cetera. We believe we'll get $200 to $250 million. So gross -- if you add all that up, we think we get to about $4.65 billion and then that needs to be used to cover capital expenditures of 3.2 that we have estimated and dividends of around $1 billion. And that -- that leaves $400 or $500 million over, which we would use to pay down debt at the current time.

Okay. And am I right in assuming that if you want to pay down $700 million in debt at Duke Capital, you need to get about that amount in asset sales?

Well, that's not -- that is not quite right. But, I mean, most of the disposals, most of the asset sales will be within Duke Capital.

We probably need a little clarity. Maybe the confusion is I said several hundred million, not $700 million, just for clarity.

Okay. Another question. What kind of capacity factors are you assuming for your base load in peaking plants in DENA?

In effect, that is provided in the disclosure.

Yes. What we have said is that we have said we have in -- for 2003, we have 89 million-megawatt hours and of which 79% is combined cycle. And, so, if you multiply 89 by79%, you'll get the estimated production of combined cycle plants and we said we're expecting them to -- the combined cycles to produce about 27 million megawatt hours. So you divide those two and I think it comes to about 34% or something. I can't quite do it in my head.

And we'll take our next question from Raymond Leong (ph) at Bear Stearns.

Hi, Raymond.

Hey, gentlemen. A couple of questions, some of my - most of my questions have been answered. But can you discuss a little bit about the collateral -- you talked about Duke Energy Trading, what if you were lowered below investment grade --what would that exposure be, and also can you confirm that Duke Capital, if you were lowered below investment grade, what that exposure may be again?

Yes. I mean, what I said in my prepared marks was that -- DETM which is -- most of our trading goes through DETM and so its movements and the DETM's credit rating that would affect collateral movements there. One notch downgrade would cause us to post $40 million in additional capital and a two notch downgrade would cause us to post $80 million in aggregate, another $40 million. In Duke Capital, a one notchdown grade at Duke Capital would cause us to post about $20 million or so of additional collateral - I mean, these are not, you know, particularly large numbers in the size of Duke Energy and our business.

Okay. Have you -- do you have a number for if you fall below investment grade at both of those entities?

Well, I mean, if you were to fall below investment grade at DETM and at Duke Capital, you might be looking at $300 million in aggregate.

Okay. And just one other fact. Capitalized interest, what was that for 2002 and was that included in the billion three and billion four number you talked about?

Yes. Well, to the extent that we will not be capitalizing interest in 2003, that is included in the 1.3 to 1.4. I think capitalized interest in 2002 was about $100 million, off the top of my head.

Great.

The swing between 2002 and 2003 for capitalized interest alone is about $100 million.

Okay, great. Thank you, gentlemen.

And we'll go next to Phyllis Gray (ph) at Dwight (ph) Asset Managements.

Hi, Phyllis.

Good morning.

I had a question about the Texas eastern transmission investment and whether that would be considered part of your core holdings?

I think that would be considered a very core holding.

It certainly would. I would call it mainstream.

Thank you very much.

And as a reminder, if your question has been answered today and you would like to remove yourself from today's queue, please press the pound sign on your telephone.

And we'll move next to Jim Van Allen (ph) at Janney Montgomery (ph).

Yes, good morning. You indicated that your dividend is very important and then one of your goals was to cut your -- I think one of your goals was cash generation, but you were also going to cut your amount of debt outstanding. If you couldn't --which one would be impacted if you got tight?

Well, Jim, I haven't had to face that decision nor has the board. We don't think we're going to be in a zone where it would be necessary for us to make that judgment. So for me to prejudge that prior to facing the circumstances probably is certainly inappropriate for me.

Can you ask it another way?

I would if I could think about it right now. Give me a couple of minutes.

We haven't stopped and prioritized those kinds of issues frankly, because we don't think we'll be faced with that sort of a decision.

Okay. Thank you.

Thank you, Jim.

And we'll move on to Kit Connelys (ph) at Morgan Stanley.

Good morning.

Good morning, Kit. How is it going?

This has been pretty thorough and so was two weeks ago. If you have it, just possibly -- a little refinement on your broad-brushed description of the cash sources and uses for '03. When you talk about $1.4 billion net income and $1.9 billion in DNA and then some from crescent, if you removed all the cash flow except that from the Franchise Electric and the gas transmission, what would those cash-flow numbers look like, cash from operations?

That would be some hundreds of millions less. I mean, DFS produces, you know, hundreds of millions of cash a year. DENA, we're not expecting DENA to produce much cash. DEI produces cash. You know, so you're looking at hundreds of millions in aggregate.

And in a three or 400 kind of range?

Yes, maybe 4 to 500.

Very good. Okay, thank you

Thanks, Kit.

And we'll go next to Paul Reisen (ph) at McDonald Investments.

Hello, Paul.

Morning. Just earlier you mentioned the impact of EITF (ph) 0203 and then FAS 143, and you said a couple hundred million. Was that each or was that combined, and then just more10,000-foot view. Given, you know, the capacity glut we're in, I'm just wondering what you're think - when we get out of that and what the swing factors there could be?

Okay. Shall I do the EITF one? I mean, what we're looking at for one time charges in 2003 in quarter one, is virtually all of it relates to the adoption of EITF 02-03, which is the change in the market to market accrual accounting and a very small amount relates to the asset retirement obligations. So we're looking at around two to $300 million pre-tax for the aggregate of the two, the vast majority being the EITF 02-03.

Okay, thank you.

Paul, with regard to your question on when do you think we'll get out of this in terms of -- I presume you're addressing reserve margins and different markets, and what have you. And again, we see a number of markets out there that still appear relatively attractive. Unfortunately, there are a number of markets that have pretty high reserve margins at this point in time. We have looked at a variety of scenarios and burn off rates and things of that sort, and there are a number of factors other than just a burn off rate of a reserve margin given the growth of continued usage. So much of it depends upon the economy to get energy use growing again and healthy, but we're looking at something around 2005 to be able to see some decided real improvement reserve margins, if you will, that we can count.

But the economy is the great big variable it seems to me in all of this in determining when things begin to tighten up. Likewise, we have seen some pretty exciting weather here of late which has clearly had an impact on the market, if you watch it. Not only that, I have watched the forwards in several markets just lift up over the last three or four months when we're capacity rich, so I don't think we all completely understand this market yet, but we're positioning ourselves to try to capture any of those opportunities as they present themselves.

I think the one market that even in spite of the economy that could firm up fairly dramatically would be the West, combination of a dry hydro-year and a hot summer would make a pretty big difference in that market even in today's economic times.

I have the West at dangerously low reserve margins actually in the numbers that I look at. Likewise for that matter, Carolinas and Virginia is fairly tight with regard to reserve margin at this point in time and forecasted to be fairly tight for a bit longer. And so we have a set of numbers that suggest some of these markets are good and will be strong, some of the markets are quite weak. Thanks, Paul.

And we'll move on to Andy Levy (ph) at Bear Wagoner (ph).

One quick question. As you look out into 2004,you know, kind of look at some of the disclosures that you gave, your hedge prices have gone down -- obviously the amount hedge also goes down as well. And also in the release, you talk about the dividend in 2003. But as you look out into 2004,it's possible that earnings could go even lower and then again, like you said depends on whose pencil is being used. But ultimately what is the view on the dividend in 2004 based on kind of what you're looking at? Is it as safe as 2003 or is it kind of a wait and see in 2004?

Well, hold on a minute while we get the crystal ball out here. The fact of the matter is that is so far out, Andy, that is pretty darn difficult to give you forecast on. I'll say this, if we continue in the path that we're continuing, we will be very, very positive cash generators in 2004. Now, that is not necessarily good news. We would much prefer to be investing and continue to grow our business, which we hope that we will, but our plan has been put together in a way in which we're very focused on cash to assure that we can meet our obligations to our investors, to the growth commitments that we already have. So the 2004 plan is pretty solid and, in fact, it gets solider as we go forward. Unfortunately, it doesn't perhaps have the growth in it we would like to have and we're working very hard to figure out how to introduce that growth. But there certainly will be cash around during that period of time.

Are there any other agencies looking at a certain payout ratio that you guys need to achieve over the next year or two?

A payout ratio on dividends?

Yes.

No, I know of no regulatory agency that --

Not the regulatory -- S&P, the rating agencies.

Maybe we didn't understand. What we've done is we've - you know, in our assumptions as we've disclosed to investors that we are - you know, our plans include a dividend of $1.10 per-share. So in a way we have given that to the rating agencies as an assumption that they can use. I mean, they can make whatever assumptions they wish. But, you know, we indicated to them $1.10 per-share.

The driver for them is interest coverage and funds flow from operations divided by debt. The dividend we pay, of course, could impact that over time, but that is not a driver for them.

Okay, guys, thank you very, very much. Good luck with everything this year.

Thank you.

And we'll go next to Luminous (ph) Management and Devon Gohagen (ph).

Hi, guys. Thanks for the time for the questions. Can you hear me?

Yes, we can hear you.

Great. I just have a couple of questions both from a (inaudible) perspective and (inaudible). You guys gave the EPS range of $1.35 to $1.60 and mentioned that, that includes some one-time gains on Crescent sales. I was wondering if you could sort of outline a range of the gains that are included in your EPS range?

Well, (inaudible) we don't count them as one time gains. I mean, this is what Crescent does. I mean, Crescent develops buildings and sells them. So we don't consider them to be one-time gains at all. I mean, that is what Crescent does.

Sure, but - I mean, then assuming that they're not one time gains-

You can look back historically at Crescent's performance and a tremendous amount of that is a result of asset sales. That is the way they make money.

I mean, it's in the order of $400 million a year, $500 million some years. I mean, but what they do is they sell buildings worth $400 or $500 million, and then they spend, you know, $400 million or so --you know, on developing, you know, buildings for the next year and the year after. So that is the development business that they're in. So I don't look at them like consuming capital. They sort of cycle capital and if you add the Crescent sales into the cap-ex as required spend, which we do, then I think, you know, it's only fair to put the income into the plus side of the equation and that is the way we look at it.

Great. If I assume -- if I assume that it is ongoing can you then just tell me what you think an ongoing sustainable stream is?

As I said, the recent past, you know, it tends to be about $400 million a year.

No, but that's - is that income? That is not income?

No. It is cash from sales.

They develop it. I mean, Crescent's profitability, you know, is the vast majority of Duke -- of what we publish into the Duke ventures line on our P&L account.

Let me just make sure we get this clear, because it is the last talk we had some media folks that went off with expansive imaginations and created a series of reports with regard to Crescent. The reality is Crescent's business plan for 2003 is the same business plan they were developing all through 2002. It is the same kind of business plan absent this liquidity crisis or anything else in this industry that they would have. So we really have not altered Crescent's game plan going forward. They're going to be operating and building their book as they always have. And then they will begin, you know, the first of the year they begin churning, which they'll do every year. The amount of churn or sale will be pretty consistent with prior years, and so there is really nothing unusual occurring there at Crescent at this stage nor did we plan anything unusual. So I thought I needed to clear that up because of some articles that have been written.

Fair enough, and I wasn't trying to imply anything. You guys give pretty good disclosure on a lot of stuff. I was just trying to get more comfortable with this business. But let me move to another question. The plants that you guys have temporarily suspended - I forget -- 2000 or some megawatts, can you tell me how much interest expense is capitalized in relation to those and how much money it would take to complete them.

I mean, in terms of capitalized interest, when we suspended them we seed capitalizing plans on those plants. So going forward, there is no --until we recommence the -- you know, the construction of those plants, there won't be any capitalized interest.

The completion, we're looking at significant hundreds of millions of dollars to complete the three plants.

Do you think, you know, $600 million is in the right range? I'm just trying to get a feel for -- I guess I don't know whether to focus on -

Five-hundred million is about the right range.

Okay. And then one last question for you guys, and again, I do appreciate the time. Are any of the plants in I guess the SPV entity which FAS now ruled on and if they are in there, have you guys -- is the drag from consolidating those entities already in your guidance?

We don't have anything like that. We're not affected by special purpose vehicles or any change in the accounting rules regarding our plants. Everything that we have is on our balance sheet. It's all disclosed. It is clear. We have never had any of those issues.

Okay. So you guys are free from that. And-

I will say that surprisingly the market in the areas where those three plants were suspended has actually picked up rather substantially over the last few months, not enough to encourage us to do anything crazy like get them started again, but the markets have truly picked up in those areas.

So maybe like in '04, '05 kind of time range.

Well, we're watching very carefully, running numbers and looking at the market with regard to what can be done in that market to support a start up of construction again. Always looking at that.

And we'll move next to Steve Fleischman (ph) at Merrill Lynch.

Hi, this is actually Jonathon. analyst Steve had to hop off. We had a quick question on the production numbers on the new disclosure and why they go up in '04 particularly and again into '05 given we did not think there were that many new megawatts coming on.

Well, you have two plants that will be finished in June of '04, so we should catch a happy year of 04 with those plants and then of course in '05 you'll catch a full year of those two additional plants.

So it is the '04 plants basically?

Right.

Okay. And secondly, do you have an estimate of what the FFO to DAT numbers at Duke Capital will look like in 2002 at this point or maybe what they'll look like in '03?

Could you repeat that question? I think we're having a hard time understanding exactly what that question was.

The free funds flow -- the funds from operation to debt number ratio at Duke Capital.

For 2002?

And maybe 2003 estimated if you have that, too.

I do not have that in front of me. That is a Moody's calculation and I simply don't have that in front of me.

Okay. Thank you.

Thank you.

That is our last question and we appreciate you taking the time to be with us today, and of course, we will be here to answer any questions in the IR department and thanks again for your time.

Thank you.

And that does conclude today's conference call. Thank you all for joining us.