Duke Energy Corp (DUK) 2003 Q1 法說會逐字稿

Good day, everyone. Welcome to today's Duke Energy first quarter earnings conference call. Today's call is being recorded. At the time for opening remarks I would like to turn it over to Vice President of Investor and Shareholder relations for Duke Energy, Mr. Greg Eibel (ph). Please go ahead, sir.

Good morning, thank you for joining us today. With me are Rick Priory, the Chairman and CEO of Duke Energy, Fred J. Fowler, President and COO, Robert P. Brace, CFO and David Hoosier, Senior Vice President and Treasurer. Today we'll provide you an overview of Duke Energy's earnings for the first quarter. Today's call is being webcast at on our Web site at www.Duke-energy.com and a copy of the slides will be available for download in the investor section of the Web site.

Before we begin, I'd like to review the Safe Harbor statement. Some of things we will be discussing on future company performance will be forward-looking statements within the meaning of securities laws, actual results may 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 be different than contemplated in today's discussion. In addition, today's presentation may have non-GAAP financial matters as defined under SEC regulation G. In such an event, the reconciliation of those measures to the most directly comparable GAAP measures will be made available on the investor relations Web site at www.Duke-energy.com/decorp/GAAP.html. We begin today's call with prepare remarks by Rick Priory and Robert P. Brace and then open the lines to take your questions.

Thanks Greg. This is Rick Priory. It's a pleasure to be with you to report our earning for the quarter and the progress we have been making on the 2003 business plan. You have talk about relying on the strongest business segments, reducing our exposure to the merchant (ph) energy marketplace and taking a set of decisive steps that we felt were necessary to work through the current down turn in the marketplace, and I'm sure that the first slide that you'll see here is familiar to most you. These are the six key strategic directives that we're keenly focused on here at Duke Energy for this year. I'll drill through them and give you an update through first quarter on each of these six.

The first is focused on positive net cash generation for the corporation. This is a clearly a key financial goal for 2003, and it was to generate $600 million in nonstrategic asset sales. To date, we have announced or we have completed the sale of approximately $1.1 billion in gross proceeds from asset sales and we expect to achieve about 1.5 billion in sales by year end. And we have taken a deliberate approach to our divestitures to insure we emerge with the right set of assets going forward. The sales include such things as the Empire and Alliance pipelines, our interest in American Refuel (ph) an our remaining units in the Northern Border Limited Partnership, we believe are positive financial transactions that have in fact not reduced our competitive or our strategic position as we move forward.

We've also reduced our capital spending to #3 billion for the year 2003, down from numbers that you remember from many years past forecasted of 6 to $8 billion or so in this year, so dramatic reduction in capital expenditure. For first quarter, operating cash flow was about $1.4 billion, compared to 820 million in first quarter of 2002, and this year we expect operating cash flow and divestitures to more than adequately fund the capital expenditures of the corporation and also the dividend. We plan to lower our debt by approximately 1.8 billion this year, setting as well along our path toward achieving a total debt reduction of $5.5 billion by the end of the year 2005. I think we're making wise and prudent decisions to reduce costs, both capital and O&M with particular focus on Duke Energy North America, Duke Energy marketing and Duke Energy field services. All these initiatives are critically important to our ability to maintain a strong and a competitive financial position.

The next key directive is investing in the strongest business sectors. We're taking a very disciplined approach to ensuring future growth in this company. Approximately 80 percent of Duke Energy's 2003 total segment EBIT is projected to come from our regulated businesses, and that's where much of our limited capital investment of course will go. You'll hear from Robert shortly on the quarterly results for each of those business, but suffice it to say now that we really believe that these business will in fact continue to turn in the solid and reliable performances that you've come to expect of those businesses. The combined earnings before interest and taxes, contribution from Franchise Electric and gas transmission for the quarter were $877 million.

Now, despite some major winter storms in the Carolinas, Duke Power delivered more power to more customers both retail and whole sale despite those winter storms. We saw increased demand for natural gas this winter and set new peak winter deliveries are all pointing to the need for additional supply as well as additional delivery infrastructure in this country, particularly in the northeast markets. Again, Robert will provide a detailed summary of gas transmissions results, but our Cornerstone businesses are cheerily delivering consistent results at this time.

The next key objective was to size these businesses that we have to fit the new market realities, and we have worked very hard on this one. We've made some tough decisions this year as focused on sizing the businesses to fit really the current market environment what the market is willing to give us. Much of the scaling back of course has been in our Merchant Energy business, but in other places as well. Our decision to exit our finance business, Duke Capital Partners is simply another good example I think of the realignment that's presently under way in the company. In today's capital constrained environment, the prudent course for us was to exit the business and to monetize the portfolio. To date, we have monetized about $80 million of Duke Capital Partners $340 million portfolio, and we expect to monetize 50 percent of the remaining portfolio by year end and then we'll complete the closeout during first half of the next year, 2004.

The next key objective was to address issues in the merchant energy business, and I do feel good about a considerable amount of progress that we have made in restructuring our merchant energy business. Duke Energy North America has been repositioned, clearly been refocused. We began with a new leadership team, the business is now becoming smaller and simpler and clearly has reduced scope as we go forward. We've discontinued proprietary trading at DENA (ph) and Duke Energy merchants which will further reduce our risk as well as collateral needs. We are focused on trading around hard assets and contract positions, and providing our customers with risk management services that they deserve, and this is really where our strengths an our true sustainable long-term competitive value will lie.

I can't leave this subject without reaffirming though, our commitment to Merchant Energy. I hope you know us well enough to know that we won't engage in businesses where we don't see long-term shareholder value creation opportunities. But we do see value and we see potential and we see opportunity within the Merchant Energy business. It is, however, a cyclical business and we expect to see improved profitability as the wholesale power market rebounds. The competitive field is clearly narrowed and we intend to be well-positioned to benefit from the recovery.

The next key objective was to strengthen our relationship with customers, and we know that the economic and market turbulence of last year left many of our customers and others customers for that matter, confused, skeptical and frustrated, and it's in these times that reliability and financial strength are critical. In this environment, our reputation for operational excellence has turned out to be a major selling point, and we're working on cementing existing relationships with our customers as well as expanding new relationships with new customers. Duke Energy gas transmission has an impressive record in customer contract renewal. They have earned a reputation for reliability that wins them repeat business time and time again in a very reliable and consistent manner. Duke power which consistently ranks high in customer satisfaction, stepping up its marketing efforts and working to develop new products and services as well as hooking up nearly 40,000 new customers a year.

Next key objective was to reduce regulatory illegal risk and all the uncertainty associated with that. We have been steadily working through a number of regulatory and legal issues. Most as you might expect related to the California energy market or in some way was stimulated by the California energy market crisis. We're encouraged by the recent FERC report that exonerated Duke Energy on charges of withholding power and manipulating power prices in California. We are confident, very confident of our facts and we're pleased that they're finally being recognized at long last. One of California's own expert witnesses referred to Duke in his testimony as the model competitor. We have had a number of other legal victories involving the western market, and we're optimistic that we'll emerge from the controversies successfully as the facts continue to sort of reaffirm our record of operating with diligence and integrity.

Earlier this week, FERC issued a White paper describing a scaled down version of a plan to deliver a market design for wholesale power in the United States. Now we need to fully review FERC's White paper, but it appears that FERC has acknowledged the important role of state regulators in the development and then in the oversight of regional transmission and wholesale market institutions, and Duke Energy continues to support a well structured regulatory market design that will bolster competitive wholesale energy markets and yield tangible customer benefits. And we believe that progress on these complicated issues depends on regional stakeholder collaboration as well as regulatory clarity and decisiveness. So in summary, these six directives have really been our focus over the last four to five months.

So let me now turn my focus really to results for just a moment. For the quarter, we reported earnings of 25 cents per share, including an 18 cent charge for the impact of previously announced accounting changes as we implemented EITF '02 and '03 and we adopted FAS 143. Before the cumulative effect of these changes, Duke earned 43 cents per share. The result we're seeing from the very deliberate drive out of the business plan provides me with some pretty solid confidence in our previously stated 2003 guidance of 1.35 to 1.60 in terms of earnings per share before the accounting changes that I just mentioned. Now, we close first quarter very much on plan, and with significant earnings and cash flows from our strongest businesses, and we have made great headway in dealing with the merchant energy downturn in reducing the exposure and strengthening the balance sheet position. So let me turn over the call to Robert and he'll review specific earnings information in more detail about each of the businesses. Robert?

Thank you, Rick. Good morning, everyone. Our regulated businesses, Duke Power and natural gas transmission delivered the largest portion of total segment EBIT for the quarter. Segment EBIT from the two businesses contribute $877 million in the quarter. The largest source of segment EBIT for the quarter was franchised electric, which reported $454 million for the quarter, an 18 percent increase over the same period last year. While the primary drivers for the positive results this quarter was the increase in sales to wholesale customers primarily outside Duke Power service territory, increased sales resulted from the gas price spike in late February and colder than normal weather.

Colder weather in our service territory provided increased sales to our retail customers and also delivered more winter storms knocking out power to approximately 350,000 customers in North Carolina. Charges associated with replacing and restoring electrical service to these customers totaled approximately $35 million. Heat in degree however hours increased 9.7 percent over last year's first quarter. This colder weather increased gigawatt hour sales by almost 13 percent over the first quarter of 2002. Not surprisingly, residential and commercial sales led the increase with 9 percent and 4 percent growth respectively. Industrial sales did not improve during the quarter. In fact, showed a slight decline of around .9 percent. The average number of customers increased by more than 46,000, representing an increase of 2.2 percent compared with the first quarter of 2002.

Also during the quarter, franchise electric began amortizing the estimated 1.5 billion in expected environmental costs associated with a North Carolina clean smoke stack legislation. This amortization expense for the first quarter was $17 million and the annual estimate for this amortization in 2003 is still about $17 million. We are still on target to meet our 2003 segment EBIT goal of 1.6 billion for our franchise electric business. Our next largest contributor to segment EBIT was natural gas transmission, and natural gas transmission business in the U.S. and Canada delivered $423 million in EBIT for first quarter of 2003 compared with 266 million in 2002. Of the substantial increase at $157 million, approximately 135 million was due to the additional two months of earnings from West Coast recognized in 2003. You will recall that we acquired West Coast last March and contributed only one month of earnings last year and obviously a full quarter this year. Excluding the additional two months of earnings from West Coast, quarter over quarter earnings increased more than 8 percent due to the incremental earnings from business expansion projects primarily connecting gas-fired power plants and storage expansion projects.

Gas transmission continues to expand its operations through the construction and ongoing development of several projects. In the southeast, Duke Energy gas transmission began construction on the Patriot project, a 94 mile extension of the east Tennessee natural gas system into Virginia and North Carolina. In the northeast, we're working to develop hub line phase two, a project that will transport eastern Canadian natural gas to the greater Boston market, and increase the reliability of natural gas infrastructure in eastern Massachusetts. In western Canada they received final approval from Canada's natural energy board to proceed with the construction of the grizzly pipeline extension which will tie production in western Canada to growing markets in British Columbia, the U.S. Pacific northwest and beyond.

Also due in first quarter of 2003, natural gas transmissions sold additional limited partner units in northern border for a gain of $14 million. We sold similar units in first quarter of last year for the same gain of 14 million, so quarter over quarter it didn't contribute to any EBIT variance. Natural gas transmission is on target to meet its annual segment EBIT goal of $1.2 billion. So combined segment EBIT from our two big regulated operations totaled 877 million compared with 650 million for first quarter of 2002, an increase of 35 percent. Franchise electric and gas transmission will continue to be the strongest contributors to the total segment EBIT and cash flows for 2003 and we anticipate they will provide around 80 percent of our total earnings for the year.

Next I'd like to review the results from our unregulated businesses starting with Duke Energy North America. DENA's results continue to reflect the difficult market conditions for the merchant energy business in the U.S. DENA reported first-quarter EBIT of $23 million, compared with $54 million last year. Earnings for the quarter we are negatively affected from reduced earnings from proprietary trading and by lower earns due in part to the required change from mark to market to accrual-based accounting late last year. In addition, DENA's depreciation expense nearly doubled due to the addition of new facilities totaling some 7,000 megawatts that began commercial operation last summer.

Earlier this month, DENA announced it will be in the proprietary trading business and on maximizing the value from the energy asset and contractual positions. While we expected around 10 percent of total gross margin to come from proprietary trading, we are not changing our annual EBIT guidance of $200 million, although the removal of this earnings streak makes achieving our DENA target segment more challenging. We now expect lower GNA expenses to help offset the lack of gross margin from proprietary trading.

Another benefit of this action is the decreased need for collateral requirements with Countercarvey (ph). Once we fully unwind the positions we reduce collateral needs by 1 to $2 million. You recall that DENA's earnings for the year were will come from a variety of sources. The low risk gross margin that will be generated from hedges that are in place and the ancillary (ph) services in run revenues are approximately $470 million for the remaining nine months of the year. Total gross margin realized in first quarter amounted to $193 million. The low risk gross margin realized in first quarter was in line with our expectations and we made progress on realizing gross margin from other sources in the quarter.

Offsetting this total gross margin for the quarter were operating expenses of approximately 170 million dollars for depreciation, plant operation and expenses and G&A. Total operating expenses for 2003 as a whole are now expect to be about $825 million. So beyond realizing the 470 million in low risk gross margin in the remaining three quarters, we need approximately 360 million from other sources of gross margin to reach our segment EBIT goal of 200 million for the full year of 2003. We expect earnings from unhedged generation sales and the optimization of our generation natural gas transportation and storage portfolios to fill that gap, and as in the past, we expect DENA's strongest quarter to be in the third quarter of the year in conjunction with a peak cooling season.

Duke Energy field services reported EBIT of $33 million during the quarter, down slightly from last year's first quarter results of 35 million. Results for the quarter benefited from the increase in NGL prices, but were offset by the effects of the increase in natural gas prices, particularly the spikes in late February by lower processing volumes and by our hedging activities. Weighted average NGL prices for first quarter, average 58 cents, compared with 31 cents for the same period last year. Processing volumes were reduced in part to the ethane (ph) rejection we used to help mitigate our exposure to the dramatic spike in natural gas prices in late February. O&M expenses at Duke Energy field services were approximately $150 million for the quarter in line with our expectation of around 600 million for the full year.

Duke Energy's international operations reported segment EBIT of $54 million, compared with $57 million in the first quarter of 2002. The 3 million reduction in segment EBIT was primarily due to a nonrecurring charge of approximately $11 million related to the timing of revenue recognition at the Kanzarell (ph) project in Mexico which was acquired as part of the West Coast transaction last year. Partially offsetting this reduction were lower G&A expenses resulting from cost reduction efforts over the last year. International energy expected to meet the 2003 segment EBIT goal of $250 million.

Now let's take look at total segment EBIT for the quarter. For first quarter 2003, Duke Energy reported total segment EBIT of $930 million compared with total segment EBIT of $706 million last year. As I said earlier the vast majority of that segment EBIT came from franchise electric and natural gas transmission businesses. We have now combined our previously reported segments Duke ventures and other energy services into other operations. The primary ongoing businesses that are included in this new reporting segment are Crescent Resources, Duke Floor (ph) Daniels, Daniel and Duke net. Other businesses currently included in this segment are Duke Capital Partners and Duke Energy merchants which we have already announced that we'll be exiting. We are in the process of monetizing the loan portfolios for Duke capital partners, and we have exited from proprietary trading at Duke Energy merchants.

The reduction in earnings at the other operations segment is primarily related to the losses associated with the exiting of proprietary trading and the exiting of the hydrocarbons business at Duke Energy merchants. One of our goals for 2003 includes the sale of certain non-strategic assets totaling approximately $1.5 billion. This chart which some of you saw on the April 22 monthly chat provides more detail on the sales that we have announced so far. To date, we have announced or closed on $1.1 billion in non-strategic asset sales and we expect another $400 million in sales this year. The after-tax proceeds associated with these sales are approximately $1.3 billion. With a reduction in asset positions comes a reduction in earnings from those assets. The impact on annual EBIT associated with the assets is approximately $155 million.

Next I'd like to briefly review Duke Energy's liquidity position. This slide summarizes the credit facilities at three borrowing notes, Duke Energy, Duke capital, and all the others as of April 21, 2003, the day before our last monthly chat. At Duke Energy, we have some 950 million of credit facilities which are used to fully back stock Duke Energy's CP program. At Duke capital, we have currently have a total of 22.7 billion dollars in credit facilities. These facilities fully back stock at, the commercial paper program. The 790 million letter of credit facility principally provides support for the ongoing trading operations. We can borrow against the unused portion of the facility.

In addition, we have other credit facilities of 1.45 billion to support our commercial paper programs at West Coast, Union Gas, Duke Energy Fuel Services and in Australia. As you can see, our current commercial paper outstanding at Duke Energy at the 21st of April was $450 million. At Duke capital, we had approximately $475 million of CP outstanding, and have posted about $550 million in letters of credit. Our other commercial paper outstanding and borrowings totaled $550 million. Therefore, our unused capacity is approximately $3.1 billion. While we have reduced our credit facilities by 500 million dollars, we have reduced our utilization such that total unused capacity actually increased by around 400 million dollars.

In addition, we had cash and cash equivalents of the 21st of April of approximately 1.3 billion dollars, and of this amount, we expect to maintain the balance of around 500 million at Duke capital for liquidity purposes. We also recently rescindicated (ph) several facilities across the company. In April, Duke capital completed the rescindication (ph) of a 252.5 million dollar letter of credit facility, and in March Duke Energy Fuel Services completed the renewal of its 350 million dollar facility, and Duke Australia pipeline financed limited completed the renewal of an Australian dollar 315 million dollar facility. These facilities were structured to provide liquidity, support and working capital for these business entities.

Next I'd like to cover briefly a couple of the trade-in disclosures that we have provided in the earnings package. I won't walk through all the tables in detail, but would like to focus on those tables of most interest, starting with daily value at risk or DVAR. Daily value at risk measures the favorable and unfavorable impact of one days price movement against the existing portfolio. We previously referred to this term as daily earners at risk. The existing portfolio includes the remaining proprietary trade-in book still in the process of being wound down and structured contracts. Our own assets are not included in this calculation. You will knows they the average DVAR amount of 21 million dollars in the quarter was higher than the past quarters and this was attributable to the price spikes in late February/early March. The DVAR calculation was 33.1 million and reflects a reduction in commodity prices and their associated volatility and is more in line with our normal run rate.

Next I'd like to review the generation hedging information. To begin our estimate of the total production available from our U.S. merchant plants for the remaining nine months of 2003 is approximately 69 million megawatt hours. This number takes into account our expectations for normal maintenance. Of the total available capacity, 80 percent of that is from our combined cycle plants and 20 percent from the peaking units. Our expected production from these plants for the next nine months is currently 22 million megawatt hours, of it 21 million megawatt hours we believe will come from our combined cycle plants and about 1 million from our peaking units. During first quarter, our plants generated approximately 5 million megawatt hours. As of the 31st of March we had hedged 96 percent of the expected power output for the remainder of 2003 at an average price of 50 dollars per megawatt hour. We have sold forward 76 percent of the estimated production for 2004 and 63 percent for 2005.

In summary, we had a good quarter and we have made solid progress towards achieving our goals for 2003. Franchised electric and natural gas transmission were rock solid and provided a strong earnings and cash flows this quarter as we expected them to. These regulated businesses will provide the bulk of our earnings this year, and our unregulated businesses continue to work hard and expect to meet their earnings goals through cost reductions and efficiency operations. We are making significant headway on asset sales and will use the proceeds to help reduce our balance sheet leverage.

Our continue focus on reducing expenses across the company, both operating expenses and capital spend willing support our debt reduction goal. We expect to reduce debt by approximately 1.8 billion dollars in 2003. We are also exiting proprietary trading at DENA and Duke Energy merchants. This will reduce collateral requirements and lower our risk profile. Our ongoing trade in activities will focus solely on maximizing the value of our energy asset positions. With these goals in mind, we remain confident and committed to our earnings per share goal of $1.35 to $1.60 per share before the impact of changes in accounting principles. That concludes our prepared remarks. Now we'll open the line to take your questions. Thank you.

Thank you. The question and answer session will be conducted electronically today. If you would like to ask a question, please press the star key followed by the digit one on your telephone. We will take as many questions as time permits and we will proceed in the order you signal us. We would like to remind everyone if you're using a speakerphone today, please release the mute button so that your signal may reach our equipment, and again it is star one if you do have a question. We'll go first to Paul Patterson at Glenn Rock (ph) associates.

Good morning. I wanted to ask just to follow up, on page 21 of your disclosure the supplemental disclosure, you have for 2003 and 2004 under owned assets the actively quoted price - I'm sorry, the fair value of the energy contracts. Is that - can we take those numbers and then apply them to what you have on slide, the last slide before the summary regarding the amount that you have hedged? In other words, you guys have about 305 million dollars worth of - worth of margin essentially in 2003, and 251 for 2004, of which you contracted.

Well, you can't quite do that because what is in the - what is in the total same value of the energy value contract net assets is really an analysis of what's in the balance sheet. On that balance sheet, we have four accounts, two in the liability side, two in the asset side, one short, one long-term liability. If you net those four, you come to a figure of 1215. The difference in the 1215 and the 1430 which is the total of that - total fair value (ph) column is the difference which Duke Energy in total and DENA. So if you looked at DENA's balance sheet, you come to the 1430.

We also have normal purchase and sales agreements which are the same contracts in some cases, the ones that are accounted for in the balance sheet. But according to FAS 143, those are not put on the balance sheet until they actually close or till they come to delivery. So if you saw part of - nothing hits the balance sheet or the P&L account until that day in '04 when the power is supplied, in which case the net margin then becomes part of the accounts. So I'm sorry, but it's not - we're analyzing the balance sheet and this is in the CCRO format, but it's not the whole story because the accounting is just so complicated.

So we can't really apply that I guess?

It's a portion of it. But you have to take the normal purchases and sales as well.

Okay. The other thing I had to ask you was in terms of the cash flow statement on page 16, there's a mark to market recognition versus realization of 116 million and then looks on page 20 that you have a 31 million dollar mark to market number for the quarter. And I'm just trying to get an idea about how they - I mean what is the total Mark to market value that you guys were - you know, gross margin that you guys recognized in 2000 - I'm sorry, the first quarter of this year.

Well, I mean, again, that's quite complicated because the rules changed, you know? The EITF '02-'03 rules changed and we have a big write off of the, you know, the 17 cents when we move from Mark to market to accrual book accounting. I mean, from a cash point of view, that amount on the cash flow, the 160 minus is the cash effect of all of the movements of that - the roll-ons, the rolloffs, you know, the things that were accounted for mark to market before it settled, et cetera. You also see on the disclosures, Paul that we also show - I think it's probably on page 20, we also show the value of the mark to market book, and that's the extent to which we have taken profit into the P&L that is not yet settled.

So we haven't had the cash, so it's the lag effect if you like. And that - on the top of page 20 it's not .3 billion so the value of our mark to market book has dropped from over $1 billion a year or so ago down to.3 as a result of the partly the Mark to market profits reducing and partly as a result of the movement to account for more things on an accrual basis versus to mark to market, which we are very comfortable with by the way. But the accounting rules have changed so much, so there's 300 million dollars of profit that we have taken in prior periods including Q1, '03, but also in 2002 and 2001 where this amount is not settled yet and the cash will come in the future periods. If you look at the top of page 21 without going into too much detail, you see on the total fair value column 197 on the right-hand side for proprietary trading that 197 is probably all mark to market. So that's component of the 300 million, and then a portion of the 217 structured contracts will also be - and the owned assets will be mark to market where they fail the FAS 143 test, and you have to mark them to market if they fail, the accrual accounting test.

Under the contract, you mean?

Within the structured contract and maybe a bit within the owned assets.

How much did you guys recognize in terms of either new deals or changes in the - of the fair value existing contracts, how much contributed to net income I guess is what I'm saying for first quarter? Do we have an idea about that?

Well, another way of looking it a I suppose is if you look at page 20, again, in the second section under DENA you see the mark to market gross margin. You see the reconciliation of DENA's gross margin, and I talked earlier on one of the slides we put on the Web site and talked about, said that DENA had 193 million dollars of gross margin in the quarter, and that 193 is analyzed there on page 20, and you can see that four of it came from proprietary trading, 42 came from structured contracts and 147 came from owned assets. The market to mark element within there was 31 million, the top line, so you've got four plus 26 plus one.

Okay. So essentially 31 is the number to look at, is that correct?

As far as the gross margin is concerned yes.

Thank you.

Thank you, Paul.

We'll move next to Jason West at Deutsche Bank.

Yeah, hi. I have a question about breakout on page 12 of the press release. The EBIT by business segment. In the other line item which is below other operations, you guys had like a 75 million dollars or so improvement there. Just wondered what that improvement was related to?

Sorry, I'm not quite with you. On the quarterly highlights you say?

On page 12 of the press release.

Page 12.

Which is quarterly highlights right.

Right. Near the bottom there's an other line item in the EBIT.

Okay.

A negative 31 million versus 107 a year ago.

Right. What caused the movement?

Right.

I mean, last year, the 107 included profit eliminations as it does this year. On intercompany trading, and last year there was a large profit in Duke Floor (ph) Daniel on sales to DENA for the completion of DENA power plants. So the large chunk of the 107 million was profit elimination at Duke Floor (ph) Daniels that didn't happen this year. So in that other line (ph) we have the corporate costs plus our intercompany eliminations and consolidation adjustments, et cetera. The main swing relates to that Duke flow Daniel elimination last year.

Does that answer your question, Jason?

Yes. Do you know how we should look at the line item for the full year? I believe it's running near the 400 million dollar range, on a full year basis?

I mean, it's very difficult for you to model because it's got all our consolidation adjustments in it. In a way, you can't model it independently of what's happening in the other lines. But I think 400 million is a bit high. I mean, I think it's going to be less.

Okay. Then one other question. Were there any other gains on asset sales or so forth in the EBIT numbers that weren't, you know, specifically laid out in the press release such as, you know, Crescent asset sales?

Nothing of any significance.

Okay. Thank you.

We'll move on to Carol Coale at Prudential Securities.

Hello, Carol.

Good morning. I've got a follow-up from Paul Patterson's call earlier just to get a little bit more clarity on the trading and marketing component of your earnings. Now, when you say that you're including Duke merchant and other operation, is that your trading?

Duke Energy merchants does some - did do some trading, but it didn't do the main DENA power and gas trading. It traded in other commodities.

Okay. I just wanted to walk through a few more numbers. Okay. On your balance sheet ...

What page, Carol?

Oh, sorry. Your balance sheet is on page -well, on two pages. On 17 and 18. I have netted out the change in your both current and long-term asset and liabilities from trading and come up with a net increase of 57 million, and since you showed a 116 million positive benefit from mark to market accounting, so we can assume that the difference between the 57 million increase on the - on the book value or the balance sheet would be a 59 million dollar profit, but yet you just said that mark to market earnings were 31 million. So I was wondering if you could reconcile the difference there? So that's the first question, reconciling the difference.

Okay. The 31 related to DENA which is analyzed on page 20, and obviously the balance sheet movements related to the total company.

I just took the 4.662 billion of assets and subtracted 3447 and got 1215.

Right. 1215 is for the total company.

Versus the end of the year, 2002, net balance of 1.158 billion, that's 57 million of a positive change. So that's what we're assuming is the increase in the value of the assets. If I'm looking at this as mark to market income, and then taking that from the 116 and coming up with ...

Yes. 31 of it came from DENA. And the DENA - on page 21 in the disclosures, we've added more disclosures than we had in the past. You can see at the bottom right-hand column there 1430. And this 1430 is the DENA component of the 1215 that you got by net in the four balance sheet amounts. I mean, I apologize for the accounting. I mean, I didn't invent it. I mean, we have to just follow the rules.

Assuming the 59 million is implied Mark to market income, 31 million came from DENA and the balance is from trading?

Well, the balance came from elsewhere. I don't readily have an analysis of that in hand, but the vast majority of the number is in that DENA, which we have analyzed on disclosures. You can see it, you know, it's a combination of the proprietary trading of the structured contracts and the owned assets. We also have normal purchases and sales agreements as I said in the Paul Patterson answer. That, you know, inline with FAS 143 am though they're similar are treated differently and don't go on the balance sheet in the structured contracts and loaned assets amounts. They don't go up and down, up and down as the market moves until the deal settles. They actually stay off the balance sheet until the deal sells. You get the same economic results and the same cash flows and same profit at the end of the day just isn't on the balance sheet in the meantime and that's just the way FAS 133 was written.

On page 15, the 73 million loss under operating revenues from trading and marketing, do we look at that as an 189 million dollar implied loss on trades that were open and closed during the quarter? I'm taking the 116 million gain and adding the 73 million dollar loss back to it and coming up with 189 million loss. So was there a loss on your trading book?

I don't think you can do that. The 73 million on the consolidated segment of income on page 15, does emanate from trading in marketing, and it's a feature of the new EITF '02-'03 treatment where certain contracts are treated gross at where you put the revenues in and put the cost of sales and certain contracts are treated net, and where the contracts are treated net, then you put the net amount in the revenue, and sometimes that's a plus and sometimes that's a minus, but it's not the whole story because you also have, you know, similar contracts treated gross where you've got the revenue up in the revenue line, but not in that traded marketing net line. Then you've got the costs down below. I mean, I apologize, it's really difficult to understand, but we're following the rules.

Maybe this is easier to answer. Weather - could you please break out how much of your electric business benefited from weather and then also in the gas business? I guess that's where you report Union Gas or Canadian distribution company, if you could give us an idea on how much weather benefited that as well. Thank you.

I think the weather - at Duke Power, I think the weather was tens of millions. I don't have a precise number. Some tens of millions to the good, but we also had 35 million dollars to the bad if you like from the cost of dealing with the ice storms. If you take that into account, and I'm not quite sure where you come out, but the number of heating degree days was certainly up in the quarter in the Carolinas. It was up over last year, and it was up over the north.

What about ...

So we ended up with stronger jurisdictional sales as mentioned by Robert. Likewise, in terms in the wholesale market, weather drove other elements of the wholesale market and we were able to also provide wholesale power into the markets that attracted pricing. So weather drove at least those two elements.

Do you have an idea what it did in Canadian markets?

Yes, Carol this is Fred J. Fowler. It did help, but it wasn't huge because we had a weather hedge on this year to protect our down side. So we didn't get the full impact of the weather on Union Gas.

Okay. All right. I'll - I may contact you off line about the accounting. Thank you very much. I know it's complicated.

Thank you, Carol.

And we'll go next to Zack Schreiber (ph) at Duquesne Capital (ph).

Hi, guys. Congratulations on a strong quarter.

Hi, Zack.

I was wondering if we can talk about what all this sort of implies as we start to tweak our models for 2004 and before we get to 2004, the 2003 should we annualize this natural gas transmission for the quarter? Does that mean that we think we'll come in sort of above this billion two guidance for natural gas transmission, or is natural gas transmission sort of lumpy with respect to the Union Gas portion which is the LDC portion and this is sort of in the second quarter and in the third quarter it should be down a bit, even given the straight fixed variable rate nature of the interstate pipes?

We're on track as we see it. It's first and fourth quarter kind of thing. As a consequence, we had a pretty good first quarter. We have to go through the second and third and then we expect -you know, we expect some uplift in the fourth quarter as well, just due to the natural behavior of that business.

So first and fourth quarter?

Yeah. I wouldn't take the first quarter results and project them. We certainly don't. We think we're pretty much on plan here at the end of the first quarter.

Is there any way to sort of quantify at the Duke Energy or North American line what the benefit was to you from the weather, whether the five million megawatt hours that you generate there was in excess of your budget and so forth?

Well, weather has a fairly limited impact on DENA primarily because we have hedged. The vast bulk of that which we anticipate taking into the market. There can be can be a bit of an uplift associated with running the plant a bit more than we anticipated, just simply due to weather. But the major impact is muted simply because of the hedging program that we use.

All right, great.

The 5.1 - 5 million megawatt hours that we produce is more or less in line with our expectations to our full year if you take the quarter of actual and the three months forecast we have given you on the disclosures on the slides are more or less are the same estimated production as we gave you in January.

Got it. And just - on the 340 million dollar of interest expense is that sort the right quarterly run rate for the year now? Or do we expect more kind of capitalized interest to be coming on line or are at we the full run rate?

I don't think capitalized interest is a big issue this quarter.

This basically picks up the West Coast, a couple of months of West Coast as well. The full effect of West Coast and as we pay down debt going forward, you should see interest rates declining - interest expense declining.

Maybe 1.2 billion for the full year or so.

And just from everything that we know now taking it in sum, and looking at the asset sales, looking at the natural gas transmission growth, continuing challenges at DENA, can you say, and I know you're not going to give official '04 guidance till the end of the year, is there any way to say directionally if we're looking at an up or down year in '04 or flat year?

I guess you're asking this obviously at the end of first quarter?

Sure.

If I were to answer that question at the beginning of the first quarter, I would have been more pessimistic than I am right now. There have been a few good things that have happened and a few things that give us some hope for 2004 that will continue to see improved behavior in this marketplace. But in terms of us locking into anything, we have to wait until a little bit later in the year to get a grip on this market to make sure we have a good solid sense of where we think it's going. But there are good indicators out there, at least in first quarter. I don't know what the second quarter going to show. You have to ask me this question at the end of the second quarter as well to get a fix on where we really believe things may be going.

I mean, are those indicators, Rich, that make you think you can hold it flat in '04? Are those indicating something we can get greedy enough to think there's upside?

We haven't run that out and extrapolated it in this point of time. David of course did a chat back on April 22 and we tried to put as many disclaimers on the net income assumptions.

You certainly did.

We say around trying to figure out, how do we put the numbers out and give meaningful credit presentation, and lay the numbers out on the table and make sure nobody walks away thinking that's what we expect one way or the other. I think we did get that one across. You just - just a continuation of flat net income was a realistic way of putting it on the table if you think next year is going to be better. If you think it will be worse, things get worse.

Thank you so much.

Thanks, Zack.

And we'll go next to Peter Quinn (ph) at Goldman Sachs.

Hi, Peter.

Good morning, congratulations on the earnings.

Thank you.

A couple questions on page 16. I appreciate all the disclosure for us. Can you discuss for us two line items. The 770 million of cash used in financing activities - I've got dividends of about 250 and debt reduction of over 100. Could you explain the additional part to that and also the positive 656 of changes in working cap fall and other, can you break that down for us? Thanks.

There are various things in there, you know, there's distributions to our minorities. There's various other things but you're right, the dividend and 250 is in there, and any movements in our debts including CP and as well as long-term debt.

But the net debt reduction is about 108 million?

Yes. For Duke Energy consolidated, that's correct.

Okay. How about the changes in working capital and other, any operating activities?

The changes in working capital and other consist of -if you look at the 656 million for 2003, there are quite a lot of things in there. One thing in there, for instance is inventory reduction, about 160 million dollars. There are some tax timing difference benefits, about 300 million dollars. This collateral reduction, we've reduced collateral, you know, over the quarter, and then working capital the difference between the - in all the receivables and the payables was moved up and down. We have about 250 million benefit within there. I mean, of course, it's all the working capital but I have given you the main numbers.

Right. And can you give us some guidance as to what you think that line would be for the full year of '03 going forward?

Well, I mean what we have done and David set it out on his call and I think the slides are still on our Web site, is we have given you what we think the cash generated will be during the year, taking into account everything that happens, not just that particular component. And including asset sales proceeds, we think we'll - and included in the benefits of our dividend reinvestment plan, we think we'll get 5.8 billion dollars gross in the quarter. We think our capex will be around 3 billion, dividend will be around a billion, which leaves us 1.8 billion net to the good.

I mean, it's easier to do it on a total basis than it is to do the individual - you know, each of the individual lines because some compensate for each other. But the main elements are set out and we can certainly, you know, take you through all that again. But the slides on the Web site of how we make up the 5.8 billion and Dave has gone through a few times on monthly chats, but that's 1.4 billion of net income. You know, add back the noncash items, et cetera. Including the benefit of our disposals which we also laid out fairly comprehensively in the 22nd of April chat. And there's a slide - if you can't find it, we'll be happy to send you another.

Right. I'd assume the defer income taxes was included in there and I was trying to figure out what else was in there and how we expect those to change quarter to quarter.

Right. I think it's difficult within 100 million to 200 million to forecast the particular line. Our working capital on an ongoing basis, over a reasonable period of time, the moment the business isn't growing very much it isn't shrinking too much. It's growing small by small amounts. We've reduced the collateral requirements, reduced the risk on the business. You'd expect working capital to be flat over reasonable period of time, maybe even a little bit positive because of the working - because of the collateral reductions. But, you know, you do get tax differences and everything else which can move, you know, 200 million between quarters to our benefit.

Great.

Over a longer period of time, it should be flattish.

Thank you.

Thanks, Peter.

We'll move on to Brian Chin (ph) at Smith Barney.

Hi, Brian.

A question for you on the increased wholesale power sales on utility. Just to follow-up. Would bit fair to say that that was more weather-driven and natural gas spike-driven and less of a increase shift on management's part to sell more power to the markets via the utility?

Yeah. I mean, our desire to sell is always high. The market conditions have to be right. We have weather, plus a series of issues occurring in the fuel markets and what have you, that presented us favorable opportunities in the wholesale market.

Great. Thank you.

Thank you, Brian.

And we'll go on to Hugh Wynne at Sanford Bernstein.

Hi, Hugh.

Hi. Two quick questions if - quickies if I could. One on page 20, in your chart under Duke Energy North America referring to merchant plant production and hedging information, is there an updated number for your projection of low-risk gross margin for '03 and '04 and '05?

We haven't given - that's fair point. We have not forecast that for '04 and '05. I mean, what we have tried to give you good visibility on '03.

And this is?

Well, for '03, we've got 193 million dollars earned in the quarter, and one of the slides that is on our Web site that we used today will show that that means we need to earn 832 million dollars gross margin in the next nine months to hit a 200 million dollar EBIT contribution from DENA, assuming 825 million expenses which as I gave you on my words I gave you an updated 825 for the total year expenses of DENA. Now, of that 832 gross margin, we have said it includes 470 million of low risk gross margin. So that means that 362 million dollars that we still have to earn in the next nine months, but the 470 million is the low risk gross margin for the nine - for the subsequent nine months.

Okay. So 470 for the next nine months and for the first three months your low risk growth margin was ...

Well, I mean, once the quarter is over, it's a bit difficult to say what it was. Because our total gross margin was 193 but the low risk gross margin was in line with our estimates. 140, 130, 140 million also in the first quarter.

All right.

Once it's happened, it's difficult to call it low risk anymore because it's happened.

No risk at this point I guess?

No risk at this point.

And the second question just to follow up on an earlier point, page 16, the changes in the working capital and other, first I wanted to confirm in the 656 number there does not appear to be a significant component of asset sales. 656 being your change in working capital in the first quarter of '03.

Yeah. I think that's fair.

That's correct? And I believe you said that there was, however, about a 300 million benefit from timing difference on your taxes by which I take you mean deferred taxes?

Right.

Okay. Very good. Thank you very much.

... it's a timing difference in most of the deferred tax.

Understood. Thanks.

And we'll take our final question today from John Olson at Sanders, Morris, Harris.

Hello, John.

Good morning. How are y'all?

Good, thank you.

Thank you. The two questions, one is kind of a side bar to one of the earlier questions. Implicitly when you have hedged your DENA power prices for '04 and '05, I'm presuming you have done a back to back hedge on the gas side of the equation too?

We remain substantially hedged, if you will, in the gas side. We don't disclose that side. Primarily we have to leave one out open so we can maintain some uncertainty with regard to our position in terms of our competitors.

Okay.

Sorry. I mean, as Rick said, we're substantially hedged and you saw you know, N the first quarter the fact that the gas price spiked and everything else. That didn't ...

Didn't hurt.

Right.

A second question if I may. Conoco, Phillips and the possibly of pushing 1 billion of Conoco, Phillips into assets is that dog going to hunt?

Well, the dialogue continues. We continue to discuss that. The plan we're talking about today and for the remainder of 2003, that kind of discussion is absolutely neutral to our plan. But those discussions are presently ongoing and I'm sure that it will come to some conclusion over time. We don't have a time frame or schedule for that, but those active discussions are currently under way.

Thank you very much.

Thank you. Thanks very much for joining us today. We will obviously be available from investor relations and see a number of you in New York and Boston over the next couple of days. Thanks very much.

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