Duke Energy Corp (DUK) 2008 Q1 法說會逐字稿

Good day, everyone, and welcome to the Duke Energy first quarter earnings conference call. Today's call is being recorded. At this time for opening remarks, I would like to turn the call over to Mr. Sean Trauschke. Please go ahead.

Good morning. And welcome to Duke Energy's first quarter 2008 earnings review. Leading our discussion today are Jim Rogers, Chairman, President and Chief Executive Officer; David Hauser, Group Executive and Chief Financial Officer; and Lynn Good, Group Executive and President - Commercial Businesses. Jim will begin today's presentation by providing a general overview of the quarter's results. Then David will provide more detail and context around the quarter's results from each of our businesses. That portion of the call will include an update from Lynn Good on the commercial businesses. Following Lynn, Jim will update you on some of our major growth and regulatory initiatives. After our prepared remarks we'll open the lines up for your questions.

Before we begin, let me take a moment to remind you that some of the things we'll discuss today concern future company performance and include 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 contained in Duke Energy's 2007 Form 10-K filed with the SEC and our other SEC filings concerning factors that could cause those results to be different than contemplated in today's discussion. In addition, today's discussion includes certain non-GAAP financial measures as defined under Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures is available on our Investor Relations website at www.duke-energy.com. As you saw in our news release earlier this morning, prior to the first quarter 2008, we presented ongoing earnings which excluded the impacts of special items and discontinued operations. Starting with today's quarterly release, we are reporting adjusted earnings, which exclude mark-to-market impacts of economic hedges in the commercial power segment as well as special items and discontinued operations. David will explain explain why we made this change in his discussion. With that, I'll turn the call over to Jim.

Thank you, Sean. Good morning, everyone, and thank you for joining us today. Most importantly, thank you for your interest and investment in Duke Energy. We had a strong first quarter. We're making good progress and resolving regulatory uncertainties, while pursuing major capital projects to ensure that we provide our customers with clean, affordable and reliable electric and gas services. As we said in our news release this morning, we reported adjusted diluted earnings per share of $0.35 for the first quarter of '08, versus $0.30 in the first quarter last year. These results reflect continued strong contributions from each of our three largest business units -- Franchise Electric and Gas, Commercial Power and Duke Energy International. One quarter doesn't make a year. But with this solid performance, we are on track to achieve our 2008 employee incentive target of $1.27 per share on an adjusted diluted basis. Now, I will ask David to give you more specifics about each segment's results.

Thank you, Jim. I'll begin my review of our first quarter 2008 business segment results with U.S. Franchised Electric and Gas, our largest business segment. That segment reported first quarter 2008 segment EBIT of 637 million, an increase of 63 million over last year's first quarter. The quarter-over-quarter improvement in segment EBIT was primarily driven by the conclusion of Clean Air amortization and the substantial completion of merger related rate reductions in 2007. Favorable weather also drove the increase in the segment's EBIT. As a result of the 2007 North Carolina rate case, we will no longer amortize our Clean Air expenditures. The unamortized expenditures of approximately 800 million will be included in rate base as they are completed. In the first quarter of 2007, we recorded Clean Air amortization for North Carolina's Clean Air Program of approximately 56 million. Merger related rate reductions also ended in 2007, with the exception of a small amount that we will continue to share with our customers in Kentucky over the next several years. In the first quarter of 2007, merger related rate reductions were approximately $51 million.

The segment's results were also positively impacted by favorable weather conditions. Heating degree days for the first quarter 2008 were approximately 5% higher than the same period in 2007 in both the Carolinas and the Midwest. The improvement in weather contributed approximately 32 million to the segment's quarter-over-quarter improvement. Franchised Electric and Gas' results were also impacted by 18 million of higher equity allowance for funds used during construction. These favorable impacts to EBIT were partially offset by lower retail rates of approximately 25 million, resulting largely from last year's North Carolina rate review, higher operation and maintenance costs, primarily due to nuclear plant maintenance and outages and decreased bulk power marketing sales, net of sharing. For the quarter, the EBIT contribution from bulk power marketing was approximately $26 million net of sharing, a reduction of 18 million when compared to the same quarter in 2007. The year-over-year increase was also impacted by a favorable settlement with the Department of Energy that resulted in the recognition of 26 million of EBIT in the first quarter of last year. Our regulated customer base continued to grow. Approximately 41,500 customers were added in the Carolinas since the first quarter of 2007, a 1.8% increase. Approximately 13,000 customers were added in the Midwest in that same time period, a 0.6% increase. Though we continue to add customers for all of U.S. Franchised Electric and Gas, kilowatt hour sales are affected by market conditions, including the general decline in the textile industry.

Next, I'll review Commercial Power. Adjusted segment EBIT was $99 million, an increase of approximately 60 million over the first quarter of 2007. The segment's improved adjusted EBIT was driven by reduced net purchase accounting expenses of 49 million, gains on the sale of emission allowances of 12 million, and a 10 million improvement at our Midwest gas fired assets. The quarter's positive drivers were slightly offset by higher operation and maintenance, resulting from plant outages. We continue to be pleased by the operational performance of our Midwest gas fired plants. Increased generation and higher capacity revenues continue to improve the results of those assets. For the quarter, these plants had adjusted EBIT losses of approximately $4 million. We now expect these assets to be EBIT positive by 2009 on an adjusted basis. Over the past year, we have highlighted the mark-to-market impact on our financial results, but continued our practice of including unrealized mark-to-market gains and losses as part of ongoing earnings. Starting with this quarter, we will begin to exclude the mark-to-market impact and present adjusted earnings. Let me give you a little background. Most of the output from our generation in Ohio is sold to our native load customers. We economically hedge the remaining output by selling the power forward and buying the associated inputs of coal and emission allowances. Certain transactions that we use to execute this hedging strategy receive mark-to-market treatment under the accounting rules. We believe that by excluding the impact of mark-to-market changes from adjusted earnings until the settlement of these economic hedges, we are better matching the financial impact of the derivatives with the underlying assets. Ultimately, we will recognize the effect of the economic hedges in adjusted earnings when the contracts settle.

Now let's turn to our international business. For the first quarter of 2008, Duke Energy International reported segment EBIT of approximately 114 million, an increase of 20 million over last year's first quarter. DEI's improvements were primarily driven by higher results at National Methanol of 21 million and favorable foreign exchange rates of 10 million. These drivers were partially offset by less favorable hydrology in Latin America. As you will recall, our earnings impact of changes to foreign exchange rates is reduced by the local currency Brazilian debt that affects interest expense. We continue to be pleased with the overall contribution of international. Next is Crescent Resources and Other. For Crescent, segment earnings were 2 million in the first quarter of 2008, which is flat with 2007. You will not be surprised that the real estate business continues to be challenged. Our Other category primarily includes costs associated with corporate governance at Duke Energy's Captive Insurance Company. For the first quarter of 2008, Other's adjusted net expense was 67 million, compared to 52 million in the prior year's quarter. The increase in Other's adjusted net expense was driven in part by increased Captive Insurance costs.

Now I will focus on a few important non-operating items. Our overall liquidity and access to the capital markets remains strong. As of March 31st, we had 642 million of cash and cash equivalents on hand. We've increased the size of our credit facility by 550 million to 3.2 billion. And through April 2008, we have issued approximately 1.9 billion in new debt, including the refunding of 100 million of our auction rate debt. I am sure you are aware of the recent liquidity issues in the auction rate security market. We have debt securities outstanding as well as investments in these auction rate securities. As of December 31st, 2007, we had approximately 880 million of auction rate debt outstanding. As I just mentioned, 100 million of this balance, which had a maximum rate of 12%, was refunded in April. The failed auction interest rate for the remainder of the debt is at most 1.75 times one month LIBOR. So the impact is not as severe as you've seen elsewhere. As we continue to review the capital markets, we may reconsider issuing hybrids and/or moving the dividend reinvestment plan to new issues rather than open market purchases sooner than anticipated. Related to our investments, as of March 31st we have classified 300 million of auction rate securities as non-current assets, due to ill liquid markets. Since we don't need these auction rate securities for near term liquidity, we can continue to hold these investments until the credit markets regain liquidity and in the meantime earn a higher interest rate.

Interest expense from continuing operations for the three months ended March 31st increased 19 million compared to the same period in 2007. This increase was due primarily to higher debt balances, as well as our foreign exchange rate impacts on Brazilian denominated debt. Offsetting this was a $3 million increase in AFUDC debt and capitalized interest over the same quarter last year. The total AFUDC debt and capitalized interest was approximately $18 million during the quarter. The effective tax rate for the quarter was approximately 32%, compared to 29% for the same period last year. Our tax rate was lower in 2007 as a result of the reduction in 2007 in the unitary state tax rate due to the spinoff of Spectra Energy. We continue to feel comfortable about our forecasted compound annual growth rate through 2012. Our teams will continue their focus on improving our returns in our regulatory jurisdictions. If we can earn within 50 basis points of our allowed return on equity on our projected rate base, and our Midwest gas assets continue to improve, our growth rate will be closer to 6% from our results in 2007. With that, I'll turn it over to Lynn Good who will discuss our commercial businesses.

Thank you, David. I wanted to spend a few minutes updating you on our commercial businesses and what we see as future growth opportunities. For today's discussion, I will frame our commercial businesses, the Commercial Power segment and Duke Energy International as a single business. A diversified, generation asset business operating in North and South America. You will recall that the Commercial Power segment includes our Ohio coal assets, Midwest gas fleet, and our wind business. To understand how we are looking at future growth opportunities, it is important to understand the scale and contribution of our combined commercial businesses. Our combined commercial businesses are expected to contribute nearly 25% of Duke Energy's 2008 adjusted total segment EBIT and own and operate approximately 12,000 megawatts of generation, 60% of which is from lower carbon sources -- hydro, gas and wind.

The capital expenditure plan for Commercial Power and DEI that we shared with you in September included the following strategic objectives: First, an expected compound annual growth rate of 8 to 10% from 2007 to 2012, measured in adjusted EBIT, before considering the benefits of expected production tax credits. Second, an improvement in the performance of our Midwest gas fleet. Third, the continued investment in renewable energy sources; and fourth, the projected investment of $1 billion in Latin America, funded by Duke Energy international's operating cash flow. We are on track for achieving these strategic objectives; and in fact, we see market conditions improving and industry trends developing in a way that creates more opportunity for growth. Let me touch briefly on three primary growth areas -- our Midwest Generation, renewables and Latin America. First, Midwest Generation. Our Midwest Generation portfolio includes approximately 7600 megawatts of generation, with approximately 4,000 megawatts devoted to serving load in Ohio and 3600 megawatts of gas fired generation. Over the last year, as reserve margins have tightened, we have seen an improvement in the value of these assets and an improvement in the earnings contribution from our gas assets. During Jim's closing remarks, he will discuss the recent legislative activity in Ohio. He will also review our expectations of the impact of the legislation on the earnings from our assets serving customers in Ohio.

For our gas assets, we continue to see improvement in margins due to both capacity payments and energy margins. PGM capacity prices have increased significantly. In 2008, capacity revenues will be $50 million, and we expect that to grow to approximately 170 million for the 2010-2011 planning year. As you know, the PGM auction for planning year 2011 to 2012 will occur later this month and we expect to bid 3100 megawatts into the auction. At the same time, our energy margins are improving as megawatt hour production continues to increase. In 2007, we saw a 70% increase in megawatt hour production year-over-year. In the first quarter of 2008, our megawatt hour production increased 53% over the prior year. With market pressure against building coal assets, the potential for retirements of aging coal plants and the long development cycle for nuclear, we see continued improvement and value in contribution from our Midwest Gas assets. As David mentioned, we now expect the results of these assets to be EBIT positive by 2009 on an adjusted basis.

Next, renewables. Almost a year ago, we acquired a wind development business and presently have 240 megawatts under construction with 180 megawatts expected to come online later this year. Our pipeline of development projects has grown from 1,000 megawatts to over 3,000 megawatts and we have the potential to grow at a pace of 2 to 300 megawatts of wind generation annually. Since we initiated our renewables business about a year ago, public policy and support of low carbon generation and rising fuel prices have confirmed our belief that renewables are an important part of our generation mix. Strong valuations of wind portfolios have also been confirmed by recent transactions in the market. We will continue to look for opportunities to add to our wind portfolio and to pursue other renewable energy projects, including solar and biomass projects.

Lastly, Latin America. Given the strong macroeconomic trends and solid power sector fundamentals in Latin America, our 4,000 megawatts of primarily base load generation is very well-positioned to deliver continued earnings growth. Power demand growth rates of 5 to 10%, coupled with tight supply margins, are pushing prices higher and driving the need for significant capacity additions. Sovereign ratings have also improved, as evidenced by Peru's recent upgrade by Fitch and Brazil's recent upgrade by S&P to investment grade. All of these factors are not only driving up the value of of our existing portfolio but have created an environment for new investment. To date, we have committed 300 million of capital to growth projects in Central and South America. Our bias has been toward green field and brown field generation projects and we have a pipeline of additional growth opportunities that we are pursuing, including acquisitions where it makes sense to do so. In summary, we operate a valuable and diversified mix of profitable generation assets in the Americas. The value of these assets is increasing and attractive growth opportunities exist in the markets we serve. Under our present plan, we believe 8 to 10% compound annual growth is achievable. To capture the additional growth opportunities that I have spoken about, as well as confirm the value we see in our portfolio of assets, we are looking at creative ways to bring additional capital into our commercial business, including partnerships or joint venture relationships. Now let me turn it back over to Jim.

Thank you, Lynn. Let me now update you on Ohio and our new generation initiatives. We are pleased that Governor Strickland signed the new Ohio Energy Bill yesterday. It is an important first step in resolving the uncertainty we face with the expiration of our rate stabilization plan at the end of this year. The next step is for the Commission to issue new regulations for the implementation of the two options we will have, an electric security plan, or ESP, and our market rate option, or MRO. We have long believed that an RSP type approach in Ohio is best for our customers and our investors. Therefore, it is our intent to pursue the ESP option as early as possible under the new law, and that appears to be in late summer. Obviously, our desire to pursue the ESP option depends on the regulations that the Public Utility Commission will issue later this year. There are many aspects of the new law, such as the excessive earnings test, that will need to be more explicitly defined. We will have the opportunity to comment on these rules when they are proposed.

Additionally, we also plan to file in June for an increase in our distribution and transmission rates in Ohio. It is our opinion that the ESP option is very similar to our existing rate stabilization plan. For instance, it provides for the mechanisms that allow us to recover periodically our fuel cost and incremental environmental CapEx. Under the ESP option, we can also seek to recover automatically other distribution costs. We realize that PUCO has a full schedule for the rest of this year. In the event the Commission is unable to act on our ESP filing by year-end under the new law, we will have continued -- we will have the ability to continue to operate under our existing RSP. We believe the risk profile for our Ohio operations and our earnings projection for 2009 will not change under either scenario. On April 23rd, we filed an Exempt Wholesale Generator, or EWG, application for 7600 megawatts which are currently owned by Duke Energy Ohio. All of these assets are unregulated. As you may recall, about 4,000 of these megawatts were deregulated by the Ohio legislature in 2000. The remaining generating assets have never served our Ohio customers under the prior regulatory regime, or under our existing RSP.

Unfortunately, the timing of our filing has created some concern by certain parties in Ohio. The primary purpose of our EWG filing was to transfer these assets to a separate corporation to gain greater financial flexibility. We made the filing pursuant to and consistent with prior Ohio Commission orders and our corporate separation plan filed and approved under the existing law. As I've said earlier, depending on the Commission's regulations being consistent with our understanding of the new law, we intend to commit the 4,000 megawatts which are committed to our Ohio customers today under the RSP to our customers under the new ESP to be effective in 2009. Now let me turn to our new generation plant projects. First, the Edwardsport, Indiana IGCC plant. Yesterday, Duke Energy Indiana filed a cost update along with our request to initiate the [quip] rider for it's IGCC plant in Indiana. The filing also requests approval for studies related to carbon capture and sequestration of the plant. The filing was made pursuant to the IURC's order approving the 630-megawatt plant in November 2007. Our revised estimate for the project is approximately 2.35 billion, including AFUDC. The prior estimate was approximately 2 billion and was developed over a year ago and was the basis of the Commission's decision last year.

The cost increases that we now project are in line with increases experienced in the past several years by other building generating plants around the world. We are in the process of finalizing the contractual arrangements with our major project vendors. These efforts include procurement of long lead time equipment. We began this step shortly after receiving the Commission's order approving the plan. In its CPCN order last November, the Commission discussed the possibility of cost increases, but refused to implement a cost cap as some parties had urged. Of course, we will need to demonstrate that these increased costs are warranted. In doing so, we will show the Commission that we continue to believe this is the best base load option to meet the needs of our customers, while at the same time minimizing our environmental emissions footprint. We will also show that this plant provides a commercial platform for the development of carbon captured sequestration at that site, an important step in our efforts to decarbonize our fleet. Equally important, it allows us to shut down older, inefficient and higher emitting coal units in Indiana. We are asking the Commission for expedited review of our filing.

Let me now briefly discuss the Lee Nuclear plant and the Cliffside unit. A construction and operating application for the Lee plant was filed with the NRC in 2007 and has been accepted by the agency. After completing our projected cost analysis of the proposed 2200-megawatt plant, we will be filing for state approvals in the fourth quarter of this year. The Cliffside plant is off to a great start. Since receiving the air permit in January, we've been excavating for the boiler building and pouring concrete for the scrubber chimney's foundation. We held a formal ground breaking in March, at which time we announced that the IRS approved the full $125 million in Federal tax credits for the project. To wrap this up, I again want to emphasize our value proposition for investors. I won't go through it, other than to say that we had a great quarter and we see no reason why we won't achieve our strategic and financial objectives. Let's open the lines for questions.

Thank you. The question-and-answer session will be conducted electronically. (OPERATOR INSTRUCTIONS). We'll take our first question from Dan Eggers from Credit Suisse.

Hey, good morning.

Good morning, Dan. Welcome.

Thank you. Hey, Jim, can you just help explain a little bit more the thought process behind the Ohio generation separation, I guess kind of from a timing perspective and then provide a little more color on your thoughts around what the financial flexibility improvements would be through the process?

Sure, I would be delighted to do that. We have been contemplating filing the EWG for a period of time and we've been working to put the filing together and quite frankly, we waited to see what the final statutory language would look like to see if it would require any other modifications to our application. And once that legislation was finalized, we then filed with the FERC. It's our judgment that the primarily purpose of that filing is to take those assets that are currently in Duke Energy of Ohio, put them in a separate corporation and quite frankly, that gives us a lot of flexibility -- and you heard Lynn talk a little bit about that -- in terms of how we finance it, it gives us flexibility in terms of the potential of bringing in a joint venture partner, so it kind of opens up for us a series of opportunities that will allow us to fund the growth in our commercial business.

So are you thinking about this potentially being a true floated spinoff or is this something that stays core to Duke and you're just looking for a way to get some more scale out of it?

We don't contemplate a spinoff. It's primarily just, again, a way to either finance it or bring in partners, because we believe this is a core business that we want to grow and develop and this just gives us more financial flexibility.

Okay. And then on the IGCC cost inflation, I guess from last year, can you -- do you have a feel for how much the rate impact will be to customers with that plant coming into service; and when you look at it relative to a CCGT option, how the cost differential looks right now?

Sure. As you know, Dan, we are in a commodity market boom. I mean, you look at steel prices, just in the last year, they're up 70%. If you look at the component parts of building generation -- boilers, turbines, tubing -- all of these costs are up rather dramatically over the last several years. This increase -- roughly $350 million is roughly 18% increase. As we look at it, when the plant is fully in service, it will translate into roughly a 2% increase in prices for consumers over the existing estimate. So again, it's a modest increase and part of that is tied, as you know, to the fact that we didn't start finalizing our arrangements with our major vendors until we actually received the certificate from the Commission in November. And that the original estimate -- and this is an important point -- was developed over a year ago based on numbers that were developed during the prior year. So, again, in this commodity boom, we expected that there might be some increases, and as we went to the finalization of the contracts and in fact there were, and so we're now in the process of presenting those to the Commission, and under Indiana law, the Commission will review this and -- over the next several months.

And Jim, remind me, that 2% increase is on top of what was the original increase for the -- on the prior bid, the prior cost?

The prior cost was about a 16% increase once it was in service.

Great. And I guess just one last question. Industrial demand still seems to be softening, I guess, in all territories. Is that economic slowdown and when do you guys -- do you have any insights into when this might start to stabilize a bit?

I think that what we've seen is obviously a lot of manufacturing facilities have gone from three shifts to two or from two shifts to one. I mean, there has been a slowdown in the economy. We don't have any sense of when it turns around. I think our economy has been remarkably strong, given the headwinds that we faced. But more to come on that. David, you want to amplify on that?

Let me add one thing on that. If you look at industrial in the Carolinas, excluding textile, it's actually up a bit -- 0.8%, as I recall. And that -- one of the things you see happening is some of the centers for people like Google and Fidelity coming into our service area, which are very significant energy users. So certainly we have issues with our economy and things like that but there are some positive things occurring, too.

Okay. Thank you, guys.

Dan, thank you.

We'll take our next question from Jonathan Arnold from Merrill Lynch.

Jonathan, welcome.

Thank you. Quick question on Ohio first. You mentioned in the slides, Jim, that you didn't see any issues with this excessive earnings test, but is one of the implications of transferring these assets that test would not apply to your generation assets but if they stay where they are, it would apply? Just wondering how we should think about that.

Well, it's never -- the filing of this application wasn't to avoid that test with respect to the 4,000 megawatts. It's our judgment that with respect to the 3600 megawatts which have never -- were never regulated by Ohio, that it is not subject to the test.

So do you -- but your understanding is the others would effectively not be subject to the test if they move?

No, it would be our -- what we contemplate is that those 4,000 megawatts will be subject to the test.

Even if they move to another --

Even if they move to an EWG.

Okay. And why would that be? Because I thought the law sort of precludes affiliates from being included in the test calculation.

Understand. But it is our intent that they be dedicated under the ESP, and because we're going to use the ESP mechanism -- assuming, again, that the rules are fair and consistent with the way we believe they will roll out -- is that they're going to be subject to the earnings test. This was not a move on our part to get out from under the earnings test with respect to those 4,000 megawatts.

Okay. Thank you for that. And I'd like to ask one on the Commercial Power results for the quarter as well, please, which is showing up 60 million I think in adjusted EBIT. But if you start with the 39 last year and add back the 49 of purchase accounting expense, and I think there was another 26 of synfuel O&M that was actually kind of in there last year, I get to a sort of adjusted base of something like 114. And then -- and so you made 99 against that, which is down a little, and if I pull out the emission allowance sales and the Midwest improvement, everything else looks like it might have been down 35 to 40 million, excluding those kind of one-times from all those non-recurring from last year. Is that a reasonable analysis and what are the factors in there? Is it all the O&M or something else?

I'm not sure totally followed all your math. But let me tell you the way I would look at it if I were you. We're looking at it that last year was about 39 million adjusted. This year's about 99 million adjusted. So that's an apples-to-apples comparison. You're right, that a big piece of the increase is the purchase accounting, just as you said. The other two significant ones are improvements in the gas plants -- the gas plants were up 10 million. And the sale of some emission allowances.

There was 26 million of O&M last year? Is that correct? From synfuels in the Q1 '07 number.

We've moved that, so that's not in that number anymore. If you recall, that's in discontinued operations.

So that O&M is not in the 39?

That's correct.

All right. That's helpful. Thank you, David.

Okay.

Jonathan, thank you.

We'll take our next question from Paul Patterson from Glenrock Associates.

Good morning, guys.

Paul, good morning.

Just to sort of follow up here on just the 32 million in -- I think that's a pretax number for weather, is that versus normal or is that just versus last year?

That is versus last year. It's about 15 million versus normal.

Okay. And then with respect to the hybrids and the new issuance that might be happening, could you give us a little bit more of a feeling for sort of what the share count might now change to as a result of that?

If you look at our plan, we had said we'd turn it on in 2010, moving [inaudible] from market purchases; we assumed a little over 200 million a year that you would get from it. So if it's 200 million a year and stock price is 20, then that gives you the share count increase.

Sure. And when might that be turned on?

We have not made that decision. We're looking at the hybrid markets. We're looking at our capital expenditures, but it's possible we would turn it on this year.

Okay. And then the Captive Insurance cost, what's going on there? You mentioned that that had gone up. Just give us a little more flavor on that.

The simple way to think about that is we set the premiums for all the business units at the beginning of the year. And then as activities occur and losses come in that are different than what were reflected in the premiums, those are simply eaten by the Captive Insurance company and so the Captive Insurance company always either makes or loses money, based on the premiums that they set in advance.

Okay. So what were those -- so there were higher losses than expected. What areas did those come from?

Most of those were associated with generation outages in Franchised Electric and Gas.

Okay, and then finally, I notice that you guys have changed and you guys went through this -- the mark-to-market accounting and sort of excluding it now from operating earnings. What was the philosophy? You know -- I don't have any problem with it. I'm just wondering what made you guys think about doing that now as opposed to previously.

A couple things. One, we'll continue to be very trans parent on what the numbers are. But the reason we bid it that way, we have a mixture of physical and financial contracts. Some of them, therefore, are not mark-to-market and some of them are mark-to-market. So you end up with a distortion of the underlying economics because of the accounting. We thought the underlying economics would be a lot cleaner if we just backed it out.

Okay, so -- but the reason for this -- okay, so you guys just got religion recently on this. Was there anything in particular that led to you thinking that way?

I think over time, the amount could get bigger and what was really happening is coal prices were running up so much, that it was a significant item in the quarter and that kind of drove the specific timing.

And the 49 million in purchase accounting expense, just for the rest of the year, how should we expect that to unfold? Because as I recall, I don't remember there being that much built in year-over-year for change in purchase accounting.

In round numbers, the number last year was 100 this year we said it would be about 10. So you should expect over the course of the year you'll be 90 million better off than you were last year.

And half of it we already got this year -- this quarter, excuse me.

That's exactly right.

Okay. Thanks a lot, guys.

Thank you.

We'll take our next question from Paul Freeman from Jefferies.

Thanks. It looks like --

Welcome, Paul.

Hey, thanks a lot. It looks like in the first quarter you got half your targeted gains for Franchise Electric and Commercial Power. Is there something that we should look at in future quarters that represents either the timing of O&M, that will hold back future quarters or should we assume that you're well on track to sort of exceed the targets that you laid out initially?

I think you should assume we are on track. We got a weather benefit, obviously, in the first quarter. O&M will certainly move around through the year. And you probably should keep in mind that the Clean Air was a big positive year-over-year in the first quarter; by the time you get to the fourth quarter there wasn't any Clean Air last year so it won't be as big a positive in the fourth quarter. But we're very comfortable with our plan for FE&G.

Secondly, I guess there's a provision in the Ohio legislation that allows for, I guess, government aggregated load. I'm not sure I understand how that would apply with respect to your unregulated generation business. Is that something that could ultimately escape the utility charge or is there some provision there that those customers wouldn't put a burden on the remaining customers if they left your system?

I think there's some ambiguity in the law with respect to that. But my general understanding is, you can't -- it's -- the charges are non bypassable even by the government aggregators.

So it's not bypassable.

It's not bypassable is my understanding.

And last question from me. I'm looking last year at a second quarter tax rate of about 28.5%. Is that a good number to use in sort of assuming the tax rate changes for the second quarter?

No. I'd use a tax rate that looks more like 32.5 or 33%.

Right. In other words -- but the comparison should be to 28.5?

28.5 that was last year?

Yes. Second quarter.

Well, to be perfectly honest Paul, I don't remember last year's second quarter tax rate. So we'll have to have the IR folks get with you. I'm pretty sure it will be something like 33 this year.

Okay. Thank you very much.

Paul, thank you.

We'll take our next question from Lasan Johong from RBC Capital Markets.

Welcome.

Thank you. Good morning. Nice quarter, by the way.

Thank you.

I need to kind of understand the mechanism of how you would charge revenues on the approximate 4,000 megawatts of assets in the unregulated sub that you will dedicate to your ESP. If I'm understanding this correctly, you will dedicate those assets based on a cost plus system where the fuel cost would be a more or less a straight pass-through. Am I understanding that correctly?

No, that's not the way it's worked under the RSP and will not be the way it works under the ESP. We will have a negotiated rate with respect to those assets, but we will have -- and you're right about this -- we will have a fuel clause that allows us to track the fuel prices up and down during future periods.

And if I'm not mistaken, Ohio is more or less a coal dominated market, correct?

That's correct.

I see. And this, therefore, does not require Duke to engage in long-term hedges for coal supply, correct?

That's correct. We can. We have the capability to do that. But historically, we have not.

Okay, so --

Primarily because we operate under long-term contracts for some of the supply. Some under shorter term. We have a mix of contract lengths with respect to our coal supply, and virtually all of those plants are plants that are on the Ohio River, so we have access to the barge trade, which kind of gives us more flexibility in terms of sources of coal for those plants, unlike many of our plants which are on a single rail line, or in the coal fields.

I see. Then if I'm not mistaken, should coal prices continue to stay high or increase from even here? The 4,000 megawatts of generation would benefit, if it were in a market environment, versus an ESP environment, whereas if coal prices fall it would be better if it were in the ESP environment, versus being in the market environment; correct?

Just depends on the contract you would have to sell the output of the plant. If you were selling the output at some fixed price, you would take the risk associated with the movement in the coal price. By negotiating a price for the use of those plants and then having a tracker with respect to fuel, we don't take on the fuel risk and we lock in the return on the facilities.

But I would assume that since your plants are pretty early in the dispatch, from what I remember, you wouldn't necessarily take a five year fixed price contract anyway. You could bid this into market without having a bid into short term agreement where you can capture the movement of coal prices up and down.

We could do that, but it's been our judgment that the better risk reward for us is from the standpoint of committing these under the RSP.

Okay. That's exactly what I needed to know. On the Edwardsport plant, I'm hearing you say you would probably do this plant with a CCS. The question is where do you put the carbon, oil and gas wells?

It's been our intent to develop our carbon capture and sequestration at that site and we will be working with the Department of Energy and others as we put the project together and finance that project going forward. But one of the great advantages of building the IGCC in Indiana at that location is because the geology is perfect for CCS.

That's what I thought.

And it would also in all likelihood, if we were able to develop the project and we have -- we're hopeful with respect to the CCS, that it would become one of the largest sequestration projects in the U.S. or in the world, actually -- and quite frankly, for us to be able to live in a low carbon world it's critical that this technology get developed.

Understood. One last question, if you don't mind. On Brazil, the S&P upgrade to investment grade; does that present any refinancing opportunities that might lower your interest costs and/or overall borrowing or cap, cost of capital?

I think the answer is yes. Historically, the Brazilian markets have been very short-term debt markets and have been inflation adjusted type of security.

Right.

We are very active in looking at those markets and determining the right time to refinance, and I won't be surprised if this gives us that opportunity.

How much debt are we talking about doing some refinancing on, and what's the benefit on interest expense, do you think?

Well, in dollars, we have about 540 million of debt. That's our share of the Paranapanema debt. The interest rate -- I think that's a question where it could move around a lot. But it could be 2 or 300 basis points.

Thank you, and we'll take our next question from --

Thank you very much.

We'll take our next question from Nathan Judge, Atlantic Equities.

Nathan, welcome.

Thank you and good morning. Wanted to follow up on your comment about 2008 earnings. I think you said there would be growth -- could be a growth rate of 6% off of your 2007 level. if you could earn within 50 basis points of your allowed return and the Miso or the Midwest gas plants were to continue to improve. Relative to your expectations at the beginning of the year, what -- could you give us a flavor on how -- well, reconcile it to your expectations, and how and what's changed so far that you're seeing that would give you confidence in that number?

Nathan, this is David, and let me make sure we're communicating. We're talking about the five-year growth rate and so when I look at the 6% that I've stated as I was going through the call there, the 6% is a good way to think about the five-year compound annual growth rate, off of '07 earnings, and that reflects two things. One is, an improvement in the gas plants, which we're getting more confident off. And two is, our ability to improve our regulatory compacts in some areas and get closer to the allowed rate of returns than we had been assuming before. So we had told you before 5 to 7%. And we wanted to put a little more color around that five year compound annual growth rate.

Thank you. Would that growth rate -- and that would be through 2012; is that correct? Just to clarify.

Yes, that's correct.

Would that include the potential earnings boost from the -- would be the Cliffside plants in 2013?

Yes. That's in total. So Cliffside, you'll earn AFUDC as you build it and then you'll have earnings on it when it goes in service; and keep in mind, this is -- this 6% is off of actual 2007 earnings that we're talking about now.

Okay. And then just on the ESP, the EWG, is there a possibility -- are you considering moving some of the Midwest gas plants that are not under commitment to the Ohio load, putting those into some type of ESP plan?

Well, I think we -- we'll have that option; but quite frankly, We're to place where we're economically indifferent and given the improvement in the economics in PJM and in Miso, it might prove to be a better economic opportunity for us to dedicate those -- I mean to use those plants in the market, rather than to dedicate them under an ESP.

If Cincinnati, Ohio Gas and Electric were to need -- I think you said something on the magnitude of 1700 megawatts, would then therefore be the opportunity to build and provide those -- that generation under an ESP?

That's one of the very positive aspects of the legislation. Given our short position with Duke Energy of Ohio of roughly 1,000 and growing to 1700 over the next several years, the ability to either buy generation and dedicate it or build generation and dedicate it, the current new law provides for that ; and quite frankly, those will be -- once we get a better understanding of the regulations with respect to it, will be making decisions as to what -- how best to meet that capacity requirement. But again, one of the things that we found most favorable in the new law is creating the opportunity for our regulated entity to build and buy and dedicate to customers' new generation.

Thank you. And then finally, just on the Edwardsport plant with the updated cost estimate, can you walk us through the process, the timing and the milestones and that and when you expect to sign an EPC contract?

This is on the IGCC, what the process is now?

Yes, sir.

Jim, you want to answer that?

Yes, this is Jim Turner. What we are going to do is ask the Commission to rule expeditiously. We're hoping for an order by the end of July on our updated application, which would both update the cost estimate that the Commission's approved, as well as initiate our first quip rider and initiate the study of carbon caption sequestration at the site.

Has there been an EPC contract signed yet?

What we have is a term sheet with all the material terms and conditions agreed to, but we've not signed a final EPC contract.

And you would wait until the Commission ruled before you sign that contract, I assume?

Well, we're going to continue working towards finalization of the contract, but we think we have enough now to initiate -- well, we know we have enough now to initiate work under the EPC agreement.

And the air permit -- when would we expect that? Would that be following the Commission's ruling?

We got that in January.

That's it, Jim. Thank you.

Nathan, thank you very much.

We'll take our next question from Michael Lapides from Goldman Sachs.

Hey, guys. Congratulations on a really good quarter.

Thank you, Michael. Welcome.

Thank you. A question on the excessive earnings test in Ohio. Not entirely sure I understand how that's going to work. Really, twofold. One, kind of bigger picture or macro, like what's the panel of companies who -- what's the comp group? And then, second, how will they likely treat the goodwill that's on the books in your Ohio subsidiary?

I think two things. One is, I think there is some ambiguity with respect to the excessive earnings test. I think that it's -- I would first make the point that this test will be a fundamentally different determination than the traditional determination of a return on equity, because it's a test that is normally done in a rate case. So I think you need to make that differentiation. I think the comp group is really going to be up to us to present to the Commission what the group looks like; and quite frankly, I think you take that from general industry, you could take it from the merchant sector -- I mean, there is a variety of comps and we'll be in the process -- and I'm sure the Commission will be in the process of defining what the comp group looks like. It's our judgement with respect to the goodwill that those were deregulated assets when the acquisition occurred and so that goodwill would be included in the calculation.

Let me just add one thing. If you started trying to back out the goodwill, you'd have to go through all the comps and try to back out the goodwill, too, because they all have it.

Understood. And you know, especially if you include the merchants and the panel there, going back three, four, five years ago, there is unbelievable amounts of writedowns and changes. Last, just kind of thinking about the Edwardsport plant, in the original order giving approval, they didn't give approval for quip on the plant at that point in time. Do you have a view or a sense about whether the Commission is willing to do it and that was just more of a technical issue?

It was a technical issue. The statue is clear with respect to quip, and Jim, you want to add to that?

Yes, Michael, the Commission did approve quip in the underlying order. What they asked us to come in and do within six months is to give them a progress update on the progress, as well as initiate the initial slug of quip, if you will -- the initial traunch of quip that we will begin to recover. So the quip doesn't just happen automatically. The Commission wants to review the quip filings every six months. So they did approve quip, but now we have to go in and actually prove up the amount of quip that we need.

Got it. Okay, thank you, guys. Much appreciate it.

We'll take our next question from Steve Fleischman, Capital Management.

Steve, welcome.

It looks like his line has disconnected. We'll take our next question from Ashar Khan with SAC Capital.

Ashar, welcome.

Good morning. I just had a question; based on this new adjusted methodology that we started, what were earnings in 2007 if you took the market to market out?

They would have been $1.23.

They would be $1.23. And David, could you also give us what it would be in the second quarter last year?

I don't have that off the top of my head, but the IR people can provide that. Sorry about that.

Okay.

I thought you were going to ask me the second quarter of this year. (Laughter) That's where I thought he was going!

Okay, thank you very much.

Thank you.

Thank you, Ashar.

We'll take our next question from Shalini Muhajan with UBS.

Thanks, and good morning.

Thank you, and welcome.

Just a couple of questions for you, Jim, on Ohio. Do you need PUCO approval to achieve the generation separation, because this involves 4,000 megawatts of the [inaudible] dedicated assets?

I think that technically, at this time, we don't. But under the new law, when it becomes effective, we will. And so as a practical point, I believe that it's going to be important to have the Commission supportive of this.

Okay. And then, if -- any talks on how long of an ESP you're looking at? Is it a minimum of three years or something longer than that?

I think that the way the statute works is that you can do it for longer periods, but they have the ability to review it every four years, and I think what that's going to lead to is shorter periods, like three year periods, rather than longer periods. And again, we don't know exactly what that review means and how it will work, and that will all be spelled out, I suspect, in the regulations. But just reading the statute and knowing how historically these things work, I think it's going to drive us to three-year type contracts versus ten year contracts.

Okay. And lastly, how should we be thinking about ROE [inaudible] -- do you go higher if you include ROC deregulated generation there, what would be the current ROE there?

I think the way I would think about it is is that we will get a determination of ROE on our transmission and distribution business, and as I mentioned earlier, we'll be filing a rate increase in June. But the standard in terms of excess earning, in which the deregulated generation would fall under is a return on common equity of comparable companies, and I think that will be the controlling standard.

Okay. Okay, oh, that's helpful. Thanks, Jim, so much.

Thank you very much.

And this concludes our question and answer session. At this time, I would like to turn the call back over to Mr. ean Trauschke for any additional or closing remarks.

Thank you, Steve. We want to thank you for joining us today; and as always, our team will be available to answer any follow-up questions you may have. And we look forward to speaking with you next quarter.