Duke Energy Corp (DUK) 2005 Q1 法說會逐字稿

Good day, everyone,and welcome to the Duke Energy first quarter earnings conference call. Today's conference 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, Ms. Julie Dill. Ms. Dill, please go ahead.

Thank you, Kelly. Good morning, and thank you for listening in this morning.

Joining me today are Paul Anderson, Chairman and CEO; David Hauser, group Vice President and Chief Financial Officer; and Fred Fowler, President and Chief Operating Officer. In addition, Keith Butler, Corporate Controller; and Myron Caldwell, our Treasurer, are also available to answer your questions today. Today's call will include a review of the first quarter results for 2005.

Before we begin with our prepared remarks, let me read to you the Safe Harbor Statement. Some of the things we will discuss in today's call concerning future Company performance will be forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements, and you should refer to the additional information and cautionary factors contained in our 2004 Form 10-K and other SEC filings concerning factors that could cause those results to be different than contemplated in today's discussion. In addition, today's discussions includes certain non-GAAP financial measures as defined under SEC regulation G. A reconciliation of those measures to the most directly comparable GAAP measures will be made available on our investor relations website at www.duke-energy.com. Following are prepared comments, and we will open the lines for your questions.

With that, I will turn the call over to Paul.

Thanks, Julie. Good morning, everyone.

This morning we reported earnings of $0.91 per basic share, which included $0.47 per share in special items for the first quarter of 2005. Our ongoing earnings were $0.44 per basic share this quarter, compared with $0.34 per share last year. That's an increase of nearly 30%. This quarter's ongoing results benefited from solid operations and a significant reduction in interest expense. The biggest improvement was seen at DENA. While they're still reporting a loss for the quarter, it was more than $140 million less than last year. The success that Bobby and his team had in reducing the earnings volatility associated with the mark-to-market portfolio was a major factor in reducing losses at DENA. Field Services saw quite a jump from $91 million to $150 million. Obviously, they continue to benefit from strong commodity prices for both crude oil and natural gas liquids. International energy boasted their results -- boosted their results by more than 60% over last year. This group made a tremendous effort to increase returns and the numbers really reflect this. Gas transmission delivered stable earnings growth for the quarter, and while we continue to see a positive trend in industrial sales, we reported lower results at our Franchised Electric business. This was primarily due to milder weather, higher O&M related to scheduled maintenance at our facilities, and lower results from bulk power marketing. The lower results from bulk power marketing were primarily due to the profit sharing plan which was implemented in the second quarter of 2004. Taking all of this into consideration, Franchised Electric continues to be a very solid performer. And although slightly lower than last year, Crescent Resources delivered another good quarter with strong sales of land and residential lots.

The next slide provides a detailed review of the special items for the first quarter. I'm not going to walk you through each item on this table, but we thought it would be helpful for you to see a summary of the special items included in our reported numbers. The majority of the special items were associated with the transactions we announced in late February. Specifically, we had gains related to the sale of the TEPPCO general partner and the TEPPCO LP units. These gains were partially offset by charges related to the dedesignation of hedges at field services, which resulted from our plan to go to a 50/50 ownership structure with Conoco Phillips. Other special items included the recognition of a gain on the sale of DENA's Grays Harbor facility and a one-time charge related to mutual insurance. All in all, it was a great quarter in my view and it reflects the actions we took last year to strengthen each of our businesses.

So with that let me turn the call over to David to review these results in a little more detail.

Thank you, Paul.

Paul gave you the overview for the quarter, so let me move on to the business unit details. Segment EBIT for Franchised Electric was 336 million in the first quarter of 2005, compared with 424 million for the first quarter of 2004. Results were lower due to higher operating and maintenance expenses of approximately 31 million, related to scheduled plant maintenance along with milder weather compared to 2004. It is important to note that the $31 million increase is not a run rate for the year. Rather, we expect total O&M for 2005 to be about 50 million higher than last year.

Bulk power sales were down slightly by about 5 million. The profit sharing associated with bulk power sales had a negative EBIT impact of approximately 20 million. You will recall that Duke Power reached a profit sharing agreement with the regulators in North and South Carolina in mid 2004. This agreement provides a mechanism to share profits from the Company's bulk power marketing activities between customers and shareholders. This quarter reflects the profit sharing while last year's first quarter does not. This sharing mechanism began in the second quarter of 2004 and was retroactive to January 1, 2004. So you should expect the year-to-date numbers to catch up at the end of the second quarter.

Regulatory amortizations totalled 85 million for the first quarter of 2005, compared with 69 million last year. We recorded a $15 million more clean air amortization than was originally scheduled for the first quarter of 2005. The additional amortization was booked in order to be consistent with regulatory expectations regarding the reported return on equity in North Carolina. The ROE Duke Power reported for the 12 months ended December 31, 2004 was robust at 13.6%. Therefore, booking more amortization expense is consistent with the overall intent of the North Carolina clean air legislation. We expect the regulatory amortization for the full year 2005 to be approximately 300 million.

We begin 2005 with another strong quarter for industrial sales, which were 6% higher than last year. Our economic development efforts are producing positive results as higher sales to non-textile industries continue to significantly outpace the decline in textile sales. Lower sales to our residential customers as a result of warmer weather were offset by higher sales to our commercial customers. The average number of customers increased 2% or approximately 45,000 over the first quarter last year. While segment EBIT was somewhat lower than last year, Franchised Electric remains on track to meet its EBIT growth target of 0 to 2% for the 2005 to 2007 period. For 2005, we would expect to be at the low end of that range, depending on our ability to add to rate base over the coming months.

Now let's move to Gas Transmission. Natural gas transmission delivered 407 million in segment EBIT for the quarter, an increase of approximately 9 million over the first quarter of 2004. Higher results benefited from U.S. pipeline expansion projects put into service in 2004 and the Gulfstream expansion which was completed in early 2005. The stronger Canadian currency was also a benefit this quarter. These results were partially offset by lower earnings at Union Gas resulting from decreased demand for natural gas and the implementation of a new profit sharing program. The profit sharing mechanism established by the Ontario Energy Board calls for Union Gas to share with customers those profits above the allowed rate of return that Union Gas would have earned under normal weather conditions. If weather is colder than normal, Union Gas will get to keep the excess. Conversely, if warmer -- if the weather is warmer than normal, Union Gas will bear that earnings risk. Natural Gas Transmission continues to expect its ongoing EBIT growth rate to be in the range of 3 to 5% for the 2005 to 2007 time period. New projects and the recently announced acquisition of the remaining 50% ownership in the Saltville gas storage facility located in Virginia will all contribute to the earnings growth of our Natural Gas Transmission business.

Now let me move on to Field Services. I know many of you already understand all the ins and outs of the transactions we announced in February. But we wanted to make sure that everyone is on the same page. In late February, we announced that Duke Energy Field Services would sell its general partner interest in TEPPCO for $1.1 billion. Duke Energy's portion of the pre-tax gain on sale was approximately $791 million, and Conoco Phillips' portion was $343 million. In addition, Duke Energy agreed to sell its TEPPCO LP units for a pre-tax gain of approximately $97 million. These two transactions closed in February. The next transaction will be the change in ownership between Duke Energy and Conoco Phillips. Duke Energy will transfer 19.7% of its current interest to Conoco Phillips. In exchange for accommodation of no less than 500 million of cash and certain assets to total approximately $1.1 billion pre-tax. This transaction is expected to close in the second half of 2005.

As we stated before, when we move to 50/50 on DEFS, accounting rules do not allow us to have hedges associated with that ownership. Therefore, the positions in place for 2005 and 2006 move to mark-to-market on February 22, the date the deal became probable. The impact of the 2005 hedges being mark-to-market on February 22 was 95 million of expense. This 95 million reverses over the balance of the year in the following way: 22 million in the second quarter, 38 million in the third quarter, and 35 million in the fourth quarter. For the calendar year 2005, this accounting change has no impact on ongoing EBIT, which is why the quarterly impacts are being defined as special items and taken out of reported earnings. The impact of the 2006 hedges going mark-to-market on February 22 was 23 million of expense. This 23 million is considered a special item because it occurred as a result of a specific deal and the gains on that deal will also be considered special items. The other EBIT line is also affected by the dedesignation of the 2005 and 2006 hedges. That line contains the mark-to-market moves from February 22 through March 31. I will review the details of those moves in just a moment.

Excluding these special items, ongoing segment EBIT from continuing operations was 151 million and compares with ongoing EBIT of 91 million for the first quarter of 2004. Ongoing results for the quarter benefited from strong commodity prices for both NGLs and crude oil. The weighted average NGL price for the first quarter of 2005 was $0.73 per gallon, compared to $0.59 per gallon in the first quarter of 2004. Given the anticipated change in ownership with Conoco Phillips and the strong crude oil prices we've seen so far this year, we would like to provide an update to the EBIT guidance for 2005. Assuming we close mid year with Conoco Phillips, and crude oil averages $50 per barrel for the year, we would expect ongoing segment EBIT to be approximately $480 million. If oil were to average $40 per barrel for the second half of the year, ongoing segment EBIT would be reduced by about $15 million. These estimates do not include any earnings affect from the changes in the mark-to-market of the dedesignated hedges, as these changes will be included in the other EBIT line item. Before I move on to DENA, I wanted to let you know that we will be putting an exhibit together in the next couple of weeks to show how the deconsolidation of Field Services will affect each line item on the financial statements. You will find that schedule in the investor section of Duke Energy's website shortly after the 10Q is filed on May 10th.

So now let's move to DENA. Duke Energy North America reported a segment EBIT loss of 35 million, including a $21 million pre-tax gain on the sale of the Grays Harbor facility. This compares with the 557 million segment EBIT loss in the first quarter of 2004, which included 359 million in special items, primarily related to the anticipated loss on the sale of the southeast plants. Ongoing results for the quarter benefited from increased margins from energy generation as well as lower operating expenses. DENA's successful efforts in reducing the mark-to-market portfolio over the last year resulted in a favorable variance of approximately 87 million from mark-to-market losses compared with the first quarter of 2004. DENA's earnings profile is seasonal and the third quarter will be key. If we see a strong summer weather and DENA is able to capture the value, their forecasted ongoing EBIT loss of 150 million could be reduced by 15 to 20 million.

Now let me move on to International Energy. International Energy's segment EBIT from continuing operations was 68 million in the first quarter of 2005. This compares with 42 million in ongoing segment EBIT last year, excluding a $13 million special item related to the sale of our investment in the Cantarell facility in Mexico. We are very pleased with the results from our international operations. Our assets in Brazil, Guatemala and Peru all contributed to higher earnings this year. We also benefited from higher prices and volumes at our National Methanol business. International Energy has started off the year well, and we still expect to see ongoing segment EBIT growth in the range of 2 to 3% over the 2005 to 2007 time period.

Crescent Resources, our real estate business, delivered segment EBIT of 52 million for the first quarter of 2005, compared to 60 million for the same quarter last year. Strong results for the first quarter were due to higher residential lot and land sales. Last year's first quarter benefited from strong sales of commercial property in the Washington, D.C., area. Crescent is off to a strong start, and we now expect Crescent's ongoing segment EBIT to exceed 150 million this year.

Other EBIT, which largely represents the cost of corporate governance at Duke Energy, will now also include the change in mark-to-market value of the dedesignated hedges from Field Services. On a reported basis, other EBIT was a negative 169 million for the first quarter of 2005. One of the special items for the quarter was a $28 million charge related to a mutual insurance liability adjustment. Also included in this quarter's results is the change in the mark-to-market value of the hedges from Field Services from the time of the dedesignation at February 22 to the end of the quarter. For the 2005 hedges, the mark-to-market move is an expense of 54 million. This amount is defined as a special item, and will reverse as follows: 10 million in the second quarter, 22 million in the third quarter, and 22 million in the fourth quarter. Again, the 2005 accounting changes will have no impact on the year since they all reverse out by year end.

Finally, for the 2006 contracts, the mark-to-market move from February 22 to March 31 is an expense of $56 million. This amount is not considered to be a special item, and will be a part of ongoing earnings as will subsequent moves in the mark-to-market of this position. While we provided guidance for other ongoing EBIT of approximately 200 million in net expenses for 2005, that amount is now subject to change as the mark-to-market valuation of the dedesignated hedges changes over time. By the end of this year, only the change in value of the 2006 contract will be a variance to the ongoing EBIT guidance of $200 million in net expenses, but we have no way of estimating what that variance would be at this time. Simply put, other ongoing EBIT is expected to be about 200 million in net expenses, excluding any mark-to-market changes.

Now let me move on to briefly review some other income statements and balance sheet items. For interest expense, Duke Energy reported a $63 million reduction from last year, from 356 million in 2004, to 293 million in 2005. This reduction is the direct result of the debt reductions which took place last year. We still expect interest expense for the full year 2005 to be approximately $1.1 billion. The effective tax rate for both quarters was approximately 34%. Cash and cash equivalents, along with short-term investments, totalled approximately 2.07 billion at the end of the first quarter. Let me remind you that this is a consolidated number and reflects 100% of the cash at Field Services. The net increase for the quarter is primarily due to the proceeds received from the TEPPCO sales less the cash used to buy back common shares for approximately $834 million. And, yes, we continue to assess the best use of this cash position for our shareholders.

While Duke Energy has already retired 30 million shares associated with the accelerated share buy-back, Merrill Lynch is still in the market repurchasing these shares and will continue to do so until mid November. As of April 30, they had repurchased 6.6 million shares. In addition to this share buy-back program, we are also working with Merrill Lynch to repurchase up to another 20 million shares. Merrill Lynch can buy shares under this arrangement through the end of the year, and we have the ability to stop this program at any time. As of April 30, they had repurchased 1.6 million shares under this arrangement.

Before I turn the call over to Fred for his comments on the Company's operations, I would like to let you know that we recently announced some key personnel changes within the finance organization which will be effective June 1. These changes have been made as part of our continued commitment to employee development. Keith Butler, who is currently the Controller for Duke Energy, will assume the leadership role in our tax department, taking the place of Cary Flynn, who will be retiring. Steve Young, who is currently the CFO at Duke Power, will step into the Controller position. While Myron Caldwell, who many of you know as our Treasurer, will rotate into the CFO position at Duke Power. Lindsay Hall will become the Treasurer. Lindsay is currently the CFO for Duke Energy Americas, and will be replaced by Lon Mitchell. I know you join me in congratulating them and wishing them the best in their new roles.

With that, I will turn over to Fred.

Thanks, David.

I'd like to briefly review some the business activities that we've been focusing on over the last few months, and I'll also take this opportunity to update you on activities that may happen later this year. Let's start with Duke Power. Our economic development efforts are starting to pay off. We're working with companies outside the textile industry to expand their operations here in the Carolinas. Companies such as Dell, Merck and General Dynamics are adding new manufacturing capacity in our service territory. This is a good start and we hope to see other companies follow their lead. In looking at capital expenditures for this year, Duke Power's -- we're still evaluating a number of potential investments. Additional CapEx is now expected to be about 100 million for 2005 for a variety of small projects. We're also evaluating some long-term generation options to add to the rate base, which could include the construction of a new coal plant and the pursuit of a nuclear construction and operating license. New generation will be needed to meet the growing base load demand over the next decade. We're also evaluating our regulatory options once we reach the end of our rate freeze at the end of 2007 for our business in North Carolina. We don't have specific plans to address this issue yet, but we do have a strong track record of finding win-win situations for both our customers and our shareholders. There's a lot of activity going on at Duke Power, and we will be hosting an investor chat on this business unit in late June.

During the first quarter at our Natural Gas Transmission business, various of our pipelines held open seasons to gauge customer interest in future transportation capacity. Open seasons for the Southeast Supply Hub, our Maritimes & Northeast Pipeline and our Union Gas Transmission System resulted in significant interest from customers; and our marketing teams have now been working with those customers to sign long-term contracts, which will underpin the investment to build out this infrastructure. Our Gas Transmission Business is also evaluating the possibility of forming a Canadian income trust, which is similar to a master limited partnership structure that we have here in the U.S. On a similar note, Duke Energy Field Services is evaluating opportunities to launch a publicly-traded limited partnership, or an MLP, within the Field Services business unit later this year. Field Services does believe that it has a number of assets that would qualify for the MLP structure, and Field Services -- they may also consider opportunities to acquire other assets that could be put into an MLP. They have recently announced that Mike Bradley will spearhead our efforts to evaluate and pursue the possibility of creating a new MLP, and if one is created Mike would be the CEO of the new MLP. As a result -- as far as the changes in ownership with Conoco Phillips, we still expect to close on that transaction in the second half of the year. And as a reminder, Duke Energy Field Services will transfer its Canadian mid stream assets, and Conoco Phillips will contribute its infrasystem in Canada to our Gas Transmission Business.

At DENA, while we didn't see any significant changes in spark spreads in either the East or the Mid West, it does appear that there may be less hydro power available in the Northwest this summer, so our plants in California may see some upside this summer if we have good weather. We're still working on a sustainable business model for DENA along two paths. The first is pursuing a transaction that's beneficial to the long-term viability of a merchant energy business. The second path is to come up with a plan for DENA on a stand-alone basis. This stand-alone plan would have to ensure that DENA, on an ongoing basis, can reach break-even at the end of 2006 and be profitable past 2006.

One of the businesses that I'm really pleased with this quarter is our International Energy Business. They delivered strong earnings, and we continue to see improvement in their returns. You may recall that we did hold back some of our available 2006, 2007 capacity from the energy auction in Brazil because we thought that we would be more successful in marking this capacity directly to our customers and our marketing teams in Brazil have done some of that. This quarter, they've signed four new contracts for a total of 34-megawatts that represents about 25% of the available capacity for 2006 and it brings our total megawatts sold forward for 2006 to 77%. Brazil held another auction for 2008 and 2009 capacity in early April. We did choose not to participate in this auction due to our disappointment in the pricing for those products. We also believe our continuing -- our continued marketing efforts will be more successful as they were with the 2006 capacity.

I also want you to -- to just mention that our International operations are a standout when it comes to both environmental health and safety. Our plant operations in Latin America have an outstanding safety record, and we're -- we're very proud of their accomplishments.

I'll end on that high note, and I'll turn the call back over to Paul for his final remarks.

Thanks, Fred.

Let me wrap up by saying that I think we're off to a good start for the year. It's a refreshing change to be able to talk more about the Company's future and not about its challenges. With Duke Energy's operations running smoothly, I've been able to turn my attention to other matters, and one of those matters you might have heard about is climate change, since my comments on that subject attracted a bit of press, I thought I might clarify where I am on that issue. In my view, encouraging conservation, increasing energy efficiency and promoting the development of new technologies will benefit all of us, no matter what your opinion is with regard to global warming. And further, I believe that we need to be proactive on this issue or we may face the broader future regulations which may not be favorable to our industry or the economy, let alone to our Company. As a result, I'm in favor of a carbon tax or similar broad-based tax because I don't believe that our industry should carry the entire cost associated with reducing CO2 admissions.

I'm also devoting a great deal of time to the future of Duke Energy. What it will look like five or even ten years from now. And while I can't lay out anything specific for you at this time, we're looking at a number of value creating opportunities. The TEPPCO and DEFS transactions are probably good examples of the type of transactions we're looking at. We're in the early stages here. I'm very optimistic about the future of Duke Energy, but again, this is an area that it's very hard to talk about until you have something specific. So I will just say that I'm quite optimistic about our opportunities for the future.

Now we'll be happy to take any questions you might have.

[OPERATOR INSTRUCTIONS]. Greg Gordon, Smith Barney.

Thanks. Good morning. On the core utility business, it looks like gross margins are running significantly ahead of your expectations in part driven by the robustness of the industrial backdrop. If you were to see your economic backdrop continue to accelerate, would we -- should we just expect that you use that as an opportunity to increase the amortization for clean air above and beyond even what is now a modestly higher forecast for the year?

In North Carolina, you would see a change in the clean air. In South Carolina, any improvement would flow to the bottom line. So that's the way it would split. But in North Carolina, you're exactly right. We would -- we would book more clean air amortization.

And am I right, looking at the numbers to see that at least year-to-date -- it's very early in the year I know, that it looks like you're a little bit ahead of where you planned?

Yes, we're 15 million ahead of where we planned on the clean air amortization.

And on the TEPPCO -- potential for the new MLP transaction at Field Services and for the Canadian income trust, you give us a sense of what the potential sort of minimum and maximum value of those transactions could be?

I really think it's premature to make those comments. We need to do a little more work.

Okay, thanks, guys.

Craig Shere, Calyon Securities.

Hi. Good quarter.

Thank you.

Couple questions. First, David, I just want to get clear. So the ongoing earnings, excluding special items, includes maybe $0.03 to $0.04 in charges for mark-to-market losses that will reverse in '06?

Well, let's be clear. There are mark-to-market losses associated with 2006 hedges that occurred between February 22 and March 31. Those are $0.03 to $0.04. They will move if the market moves this year. So if the price of oil drops, then you will see those move in our favor. If the price of oil rises from where it was at March 31, you'd see them move against us.

Right. But the net effect of whatever happens this year will wash out by '06?

Not for the '06 hedges. The '05 hedges washout by the end of the year.

Yes. The '05 hedges washout by the end of the year. The '06 hedges would be marked-to-market at the end of the year, and then whatever happens in '06 to the price of oil would affect them.

Okay. I guess what I'm just trying to say is it will -- the '06 -- ignoring '05, the '06 hedges when they settle in '06, all the mark-to-market effects will have offset by the end of that period?

By the end of '06, yes. Certainly.

That's exactly right.

Okay. And I don't know, Fred or Paul, if either of you want to respond to this, kind of, Fred, on your comments about finding a JV partner for DENA and the possibility or the goals, if it were, to go it alone, previously you all seemed pretty confident or at least had a strong goal of trying to find a JV partner before the end of the year. Can you kind of characterize where those discussions are and maybe some of the probabilities of this finding its way into a more economic partnership?

I'll spare Fred having to say no. We still are vigorously pursuing a JV partner. I think Fred's comments are simply we aren't going to come to the end of the year and suddenly find that that track wasn't fruitful, and we don't have a fall back. I think it's prudent to run the dual track and say, We are going to proceed on the basis that we don't have a JV partner, but that in no way diminishes our enthusiasm for our efforts in finding a JV partner.

Paul, are you still willing to consider very deep-pocketed strong balance sheet financial players that don't necessarily have as much hard assets on the ground as yet as potential partners?

Sure. I think we would -- we'd have to put everything in context. But just as a starting point, the strategic aspects of a partner are more important -- well, not more important, but certainly as important as the financial character of the potential partner.

Okay, thank you.

Maureen Howe, RBC Capital Markets.

Thanks very much. I'm just wondering if you can give us little more color with respect to the outlook for Duke Energy Field Services? In particular, if oil was to say stay at a $50 level, can you give us some idea of what 2006 EBIT might look like?

We haven't -- we haven't put out anything for 2006 EBIT guidance for DEFS, and I don't think we're prepared to do that at this point.

What about just for the -- for the last half of the year after the transaction is -- let's assume the transaction closes mid year, can you give us a idea what the last six months would look like for 2005?

That's where I gave you the guidance that if it moves from $50 oil to $40 oil, that's 15 million of EBIT. That is in the back half of the year.

Okay. And just with clarification, this is for the DENA table, when you break out the percent of contracted capacity, can you just specify what you characterize as capacity versus energy? This is on page 15.

Yes. Well, let me just make sure we're -- we're at the same point here as far as what is capacity and is what energy. Capacity is simply access to the plant. Energy -- so that's megawatts. Energy is the megawatt hours produced by the plant. So ask me your question one time. I'm not sure I'm clear on it.

Well, I just want to understand what you are, in fact, referring to. I mean, capacity, I guess I'm wondering are you referring to a capacity payment or a tolling arrangement?

Capacity. Okay, let me answer it this way: we will do different types of contracts with different parties. And in one case, you would sell people the right to operate the plant. So they have a call on the plant. If they opt -- they will pay us a fee for that, so they pay us a tolling fee. If they operate it, then the cost of the operation, the fuel costs and all that, is on their nickel. So they're taking the risk of that. In other cases, we have sold forward energy; and in that case, we've actually sold forward megawatt hours. So that's the capacity versus the energy. Is that helpful?

That is helpful. Thanks very much. And then also I'm just wondering if you can tell me -- for the Maritimes & Northeast, you recently had what looked like pretty successful indications of interest. And I'm wondering there, are you -- are you really looking at an expansion of that pipe? Or are you looking at potentially participants in the Sable Island offshore development, perhaps putting back some of their capacity on that pipe and then maybe reallocating to new potential shippers.

Yes, Maureen. We will have a reverse open season once we get to that point in the process, and we would expect some capacity turn by, but we also expect expansion as well. And we're at a point that we -- we have a lot of flexibility because the expansion -- this next expansion on that system will be compression.

Okay. That's great, Fred. And maybe one last question and that has to do with a potential Canadian income trust. You have a number of assets in Canada. Most, I think, of which are regulated, although I do believe you have some non-regulated plants in British Columbia. Can you maybe give us a idea of what assets you might be looking -- well, I guess you could put the Maritimes & Northeast in, but -- and what assets you might be looking at putting into that potential income trust?

Again, Maureen, I'm going to give you the same answer I gave on the MLP. I think it's a little premature to have that discussion. But as we do formalize our plans, we will definitely lay them out for you.

That's great. Thank you very much.

Paul Fremont, Jefferies & Co.

Just a couple of points of clarification. The gain on the sale of Grays Harbor is broken out as a special item, and yet it's included in the 35 million EBIT loss number at Duke Energy North America. So when you guys talk about being able to do 15 to 20 million better than your EBIT guidance on the year, is that including or excluding Gray Harbor? And I guess, how come the DENA number doesn't really adjust for that to show a loss of 56 million in the first quarter?

On the Duke Energy North America slide on the ongoing segment EBIT, it shows a $56 million loss for the first quarter. And 198 million for the first quarter of '04. So that's the 142 million of improvement that we've been talking about.

So the -- the 15 to 20 million improvement then does represent an improvement, even excluding this gain?

That's exactly right.

Okay. I just wanted to make sure that that was the case.

That's right.

And then I guess I'd point out sort of a similar -- at Field Services, it looks as if -- if you take the mark-to-market adjustments on the dedesignated hedges that you actually would've had an adjusted EBIT of 205 million instead of 151 that you show in the press release. Is that sort of a correct way to read that?

I didn't follow -- I don't have that number. I didn't follow that math exactly.

Well, I guess the adjustments in your press release strip out the 90 -- the 791 million gain, the 97 million gain, and the 118 million in charges. But don't strip out the 54 million in mark-to-market losses on dedesignated 2005 Field Services hedges.

It's in the other EBIT line. It's not in the field services line.

I got it.

That's the distinction.

Okay. And then one or two -- one other question. Is -- is there any progress or -- in terms of recontracting any of the California power plants that are owned by DENA? Or have they been recontracted?

Yes. And we have done some recontracting. Actually at this point, on a recent market dip that we had awhile back, we actually took off some of our summer hedges this year to free up the plants just because of how we saw the summer setting up in California.

And that's where we made the comment during the talking points that if the summer turned out hot in California, you might see us beat the 150 million that we've talked about as a loss by maybe 15 to 20 million.

Yes. Because you've seen much better pricing, I guess, in California. The last question is, can you quantify the currency adjustment at Gas Transmission?

Yes, it was 13 million for the first quarter.

Thank you.

John Kiani [ph], Credit Suisse First Boston.

Good morning. Can you elaborate a little bit on what your thoughts are on your ownership of the international businesses over the medium- to long-term?

Well, what we have -- have said with regard to international is that for the medium-term, we have given them a challenge of getting into a double digit returns. In fact, basically what we've said, we expect them to at least beat what we can get in the power company, if they have international operations. And they have laid out a good plan that shows increasing returns over the next two to three years and growth of EBIT. So we have basically kind of left it on the basis as long as you're improving and you're on that plan, we're happy. Though I would say long-term we don't have any strong imperative to build international operations. I guess if you said somebody would come in tomorrow and offer us a premium price because it was worth a lot more to them, I probably would listen to that. I guess -- does that answer your question?

It does. I just have one more question. I know you've already discussed it a little bit, but can you elaborate a little bit more on your strategy for DENA to move to EBIT breakeven and how the potential structures that you're evaluating might help you get to that point?

Just -- we're continuing to try to move that business much more to a physical marketing business as opposed to a -- the way it was initially built more on a training and marketing model. We continue to try -- to work on driving our cost down. We continue to work out of some of our hedge positions as the market -- as the markets allow us to. As I mentioned earlier, we did take off some hedges in the California market when we got an opportunity that we felt was the right time.

To me, the major driver that you're going to get out of a transaction is the fact that these are pretty high overhead businesses. If you look at it, the overhead of DENA is around $150 million a year. And we think you could run -- we think you could run a business three to four times the size of ours with about that same kind of overhead. So one of the drivers on a transaction is just to do a combination with another company where that you can eliminate that kind of cost.

The other thing that we're looking to do is rebuild our gas marketing business. We had -- traditionally in recent years we had done that through a joint venture with ExxonMobil that we're -- we've been in the process of shutting down. We're now to the point that we can go out and rebuild that business so that will be a major leg of the improvement as well.

Great, thank you, that's helpful.

Karen Taylor, Nesbitt Burns.

Quick question just regarding the Field Services, and I know with the deconsolidation you can't have hedges any more, but can you just talk about where you are in a hedged position overall in the various commodities within that portfolio?

The -- probably the easiest way to look at it is for the second half of the year if you were allowed to have hedges, we'd be 79% hedged.

And can you break that between the oily part of the barrel and the -- I guess the non-oily part which you've done before?

I don't have the specific hedges, but basically the oil is 40% of the barrel and that is hedged in oil. And then the propane is hedged in propane.

So are you 100% hedged then notionally on the oil part of the barrel, and what part would that be on the propane side?

I don't have the specific numbers, but the answer is we're essentially 100% hedged on the oil part.

Okay. And just a quick follow-up on the Canadian MLP. I know -- or income trust, or whatever you want to call it. It is early days and I appreciate that. Given your total portfolio, you must be talking about the non-regulated side because regulated side as far as I was aware isn't necessarily receptive to that as of yet. Can you just indicate whether that view has actually been changed by any decision that I may have missed?

I think for the Canadian income trust, it's fair to say that Union Gas isn't really on our radar screen right now for that. And so I think that's the big regulated one that you'd be talking about.

Well, even the NEB regulated facility which includes both a gas gathering and possessing in BC, at least a good chunk of it, and the main line pipeline, again, I'm not aware that the NEB has changed its stance there either. But that is on the table, as far as you are saying.

I think I said that we haven't taken it off the table yet.

Okay.

But as Fred said, there certainly have not been any decisions made.

Okay. And that's it. Thank you.

[OPERATOR INSTRUCTIONS]. Dan Jenkins, State of Wisconsin Investment Branch.

Hi. State of Wisconsin Investment Board. First, I was wondering on your cash flow statement on page 14 of your release, it looks like the cash from operations is down about 270 million from last year. I was wondering if you could give me some detail on that, what's driving that?

The vast majority of that is the increase in collateral associated with the hedge positions at Duke Energy Field Services.

Okay. And then I assume the net cash used in financing that's primarily the equity buy backs, that correct? The difference there?

Hang on one second. Okay. The cash flow from financing would be associated with the equity buy backs. I had kind of like look to make sure I had the right things in the right lines there. But that -- that is associated with the equity buy backs.

Okay. And then on page 13, your balance sheet, I was wondering how much debt is included in the current liability lines? Is there any debt in there?

Yes. Current maturities of long term debt are 1 billion 556. And additional -- these commercial paper of 100 million.

100 million of CP. Okay, then I was also wondering on DENA, you mentioned part of -- a big reason for your improvement was successful efforts in your mark-to-market book. And I was wondering how much more of that proprietary book is still left to be worked down or finalized?

Very little. We've pretty much -- we've pretty much balanced that book.

It's a big book. But it's balanced. I think that that's -- that's the significant thing.

David Reynolds [ph], Tribeca Global Management.

Yes. Good morning. Just wanted to get an update on the capital deployment strategy. You're now into two buy backs here with the second one going on. Has there been any more thought to change in the dividend, and when would we be thinking about a decision time on that?

Well, the board typically looks at a dividend at their May meeting. This is May and we have a board meeting coming up. And so it's premature to make any comments on that. We-- it will be a consideration that -- at the May meeting, but what they decide to do is up to them at that point.

And what day is the -- what day is the May meeting?

May 12th.

Thank you very much.

Matthew Akman, CIBC World Markets.

Thanks. I guess maybe this is for Paul. I guess in the last conference call you said you don't like to have a lot of spare cash sitting around, and yet creating income trusts and MLPs, I guess, would get more cash in the door. So maybe just from a philosophical standpoint, would you do those deals just because you can get high prices for those assets now, or only do them if you saw a transaction imminent in the use of that cash imminent?

Well, the driver for the MLP is -- is really to be strategically positioned to be able to participate in transactions with a mechanism that allows you to compete. Because -- most of the transactions taking place in the Field Services area, or many of them right now, are being driven by master limited partnerships and the lower cost of capital is important. So it's not -- it's not so much to generate cash from creating the MLP, but it's to create the mechanism that you can then grow. And the same thing to a lesser extent with income trust. And I think the income trust is probably a lot more gleam in the eye than the MLP, if you will, in terms of our decision that it's the right thing to do.

Okay, maybe I can get a similar question in a different way. In terms of cash, I guess you guys have a couple billion dollars, but to do any significant transactions, you've got some money tied up in the share buy back. I guess, would you need to sell more assets, or where do you see sort of the cash balance going without selling more assets as we get through the year?

Well, I think at this point in time we're quite comfortable that we don't need to sell any assets or do anything from -- being driven from a cash perspective. We will only sell assets because we get a great price for them or strategically they don't make any sense to us. David, you might want to just comment on -- in general where our cash position is.

I want to make one point clear because you talked tied -- cash tied up with the share buy back. The cash for the 30 million shares went out the door before March 31. The only thing left on that is a true-up as Merrill Lynch covers the short, whichever way the true-up goes. So the vast majority of that cash is already out the door. I think the other thing that's going on is we are looking for opportunities in a couple of our core businesses. We think Gas Transmission may come up with -- may have some more opportunities, and we think Franchised Electric may have some more opportunities, especially if they build a generation plant. So I think as you look -- as we look at our cash, we'll be looking at opportunities to deploy some of it in those key businesses.

Okay. Thanks very much.

Nathan Judge, Atlantic Equities.

Good morning. I wanted to follow up on your question with regard to some of the improvement in the California markets with regard to DENA. In -- last year you mentioned that there was some element of expected improvement in the markets that needed to be there in order to breakeven in '06 with regard to DENA's EBIT. How do we stand today relative to your expectations then?

I'm not sure I understand your question, Nathan. This is Fred.

If the question is is California looking more positive than it looked a year ago, I'd say that for -- certainly for this summer it's setting up to look pretty positive.

It seems to me that as we look across the country that there is an improvement. But what I'm trying to gauge is relative to your expectations, I think when you originally set it out in February of 2003 -- or excuse me, '04, I think there was an indication that there was some expectations that the market would improve.

Yes. I think for -- for '05 we have an awful lot of our capacities in California sold. Especially during the peak periods. So for us to get big improvement out of markets this year, other than that capacity that I talked about earlier that we freed up for the summer, what we need is we need better markets in the Mid West as well as the Northeast, where we have more available capacity.

Could you give us an indication what the same type of number would be for '06? If you had similar-type weather?

You mean comparable to the 15 to 20?

Yes, sir.

We haven't put a number out like that, but one of the things you might want to note on our disclosures is that in '06, previously we had 42% of the energy sold and it's down to 34% now. And that's because we've opened up some of the positions in the West in the summer next year. So we have more potential next year because of that.

And as far as capacity payments, could you just give us an update on what you're seeing in the market as far as any measures as far as kilowatts -- dollars per kilowatt per year?

[inaudible - overlapping speakers] -- in front of me.

We're kind of all looking at each other. The capacity payments, I will tell you that the payments for capacity to date have been pretty sorry, because I don't think the -- just generally in almost all markets because I don't think that the system operators to date have accepted the fact that they're going to have to seriously compensate generators for having capacity available. But we're starting to see a movement in that area. But to date we haven't seen anything very robust.

Thank you. And just finally my last question. What would need to happen, and how long would it take, for a serious investment into the ground with a new nuclear plant.

Well, there's -- there's a couple of key things. I've actually had quite a few conversations with our friends in Washington over this because they asked me that question directly. The real critical thing is we've got to have some assurance that there'll be a place for the spent fuel to go. And Yucca Mountain is very critical to -- or a Yucca Mountain substitute, is very critical to come up with a solution for where the spent fuel goes. The second thing is we have talked with the Department of Energy about alternatives in which they might ensure is the word they use, but you might say underwrite a -- an investment in a nuclear plant to the extent that it ends up [technical difficulties] - procedural hang up makes a completed plant sit there for an extended period of time. We need some sort of assurance that we -- we will not be left holding the bag on that. So those two things we really need before we would go forward with a nuclear plant. I don't think that we would expect to see actually breaking ground of a plant in the next five years.

Ali Agha, Wells Fargo Securities.

Thank you. Good morning. Paul, could you just remind us again, what is the EPS target that's baked into your '05 incentive plan?

It's $1.60.

$1.60. And I'm assuming Q1 is putting you nicely on track for that?

Well, the one of the things that we've done is we've avoided any kind of guidance beyond telling you what our plan is. But I don't see anybody slitting their wrists right now.

And what's the average share count we should be assuming in that $1.60 plan?

The average shares are --?

Well, the shares outstanding today are 928. And so that reflects the 30 million reduction that has occurred. So that'll be phasing into the 12 month average over the year.

Right. And -- but there was this other 20 million program that you also have. Should we assumed most of that should be done by the end of the year?

If we do that 20 million, of course, we said we can stop it at any point. But if that 20 million occurs, it would occur by the end of the year. But of course you use a 13-month average to calculate the shares, so it wouldn't have a 20 million share impact for the year.

Right. I guess what I'm getting at is to get to your assumed budget for that $1.60 target, do you need to have bought back those 20 million shares?

No.

Okay. Thank you.

And that does conclude the question and answer session. I'll turn the conference back over to Ms. Julie Dill for any closing remarks.

Great. Thank you, Kelly. And thank you, everyone, for joining us today. As all, my team and I are available to take your questions afterwards, and we thank you again for your participation.

That does conclude today's teleconference. Thank you for your participation.