愛迪生國際 (EIX) 2006 Q4 法說會逐字稿

Welcome to the Edison International's conference call.

This call will be available for replay at the following numbers: 877-693-4277, and international, 402-220-0042. You will need to use the PIN code 11101 to access today's call.

For your information, this call is being recorded. Also, we want to advise you that Edison International is holding a simultaneous webcast of this conference call. This will be on the Company's website in a listen-only mode for interested parties.

[OPERATOR INSTRUCTIONS]

Thank you, again, for your patience.

At this time, I would like to introduce your host, John Bryson, Chairman and CEO of Edison International. Thank you, and go ahead, Mr. Bryson.

Good morning to all of you. Thank you for joining us today. We appreciate that. We will follow the usual format.

We would provide opening comments. Tom McDaniel and I will do that, then respond to your questions, and we begin, as always, with a reading of the forward-looking statement advisory. Barbara Mathews will do that.

During this call we will make forward-looking statements about the financial outlook for Edison International and its subsidiaries and about other future events. Additional forward-looking information, as well as a reconciliation to GAAP of any non-GAAP measures discussed in this call is available on our website at www.Edisoninvestor.com.

We believe this information to be reasonable and well founded. However, actual results could differ materially from current expectations. We have set forth important factors that could cause different results in Edison International's 2006 form of 10-K report filed today.

We encourage you to read this report carefully.

All right. Thank you, Barbara.

I'm going take just a little more time at the outset here with some opening overview comments, and I'm going to talk about our results for the entire year of 2006. Some of you will have followed this closely throughout the year. I thought it might be helpful to give an assessment and comment on the effects overall of our results in 2006.

They were strong consolidated earnings set a record for us growing almost 4% to reach approximately $1.2 billion, that's $3.58 per share, compared with $3.47 per share a year ago. Core earnings, which as you know, exclude discontinued operations and nonrecurring items were $3.07 per share in 2006. That is a decrease of about 2% over the prior year, as core earnings of $3.13.

And then finally, in December, something our shareholders are very focused on, the dividend was increased by 7.4%. That results in $1.16 per share taken on an annualized basis.

Thinking about the year as a whole, I think the most important thing to report to all of you is that as a result of the accomplishments of the past two years, 2006, with good work also in 2005, accomplishments, supportive decisions over the past two years, we now have a considerably stronger -- I think the right way to describe it is a yet stronger foundation to achieve large scale growth in our business over the next five years.

And most of you will recall that in October 2004, we went out with our strategic plan that set forth the then forward five years. It was at a high growth level that had been projected. We have exceeded that.

So let me take us a little in piece parts, overview Southern California Edison. We are increasing now our growth estimate for earning assets, so that's for rate base in the utility to an estimated 12% compounded annually, potentially more than that for the years 2007 through 2011, that five-year period. Now, that estimate assumes that we receive some necessary regulatory approvals.

The required approvals, we believe, will be consistent with existing state and federal policy. At our unregulated power generation subsidiary, the Edison Mission Group, that has likewise performed well since the outlook provided in October 2004. I'm going to turn for this purpose just to one measure of the position that the work the past two years has put us in.

Some of you are accustomed to looking at independent power as measured by EBITDA, effectively the cash generation power of the business over each of the past two years. Cash generation at EMG has provided in EBITDA terms about $1 billion each year, and that $2 billion total exceeded our projections in the October 2004 timeframe by more than $0.5 billion.

So that cash generation conveys something about the resulting financial health and strength at our independent power subsidiary and that, notably, allows us now to undertake what we call a diversified growth initiative.

Now, let me just take you a little further briefly into the Southern California Edison foundation for growth. Four things highlighted, first is the need for large scale continued, continuing into the future investment in the Southern California electricity infrastructure. We need that, many of you have followed this, to maintain and to strengthen reliability and to keep pace with our regions very rapid economic growth.

Last May, the California Public Utilities Commission recognized all that, supported the need for this infrastructure investment by approving about 98% of the capital requested in our 2006 general rate case. That amount is about $5 billion of new capital investment for the years 2006 through 2008. I'm pleased to say that through 2006 we are well on track to get that job done.

Second, during the heat wave in California, Southern California in particular, last July 2006, but it hit across the state. Peak demand in our service territory reached a new record. This made clear the need for additional generation, particularly important were quick start peaker units.

Governor Schwarzenegger, the PUC, responded with an order that Southern California Edison construct five such peaker plants targeted to be in service now by August of this year, August 2007, about a $250 million investment in addition to our earning assets.

Third, we continue to make progress in the construction and always difficult permitting for a nearly $4 billion expansion of our transmission system. Particularly significant is our Thachapi renewable transmission project that is an estimated $1.7 billion investment.

It will make possible the development over the next several years of substantial new wind farms in what are currently remote areas of Eastern Kern County in California. That is the nation's first transmission project built primarily to enable development of renewable energy.

And then fourth, last on the list is the development in which we have catalized vendors to come forward with truly advanced electricity meters. In 2006 our work to spur development of this next generation of smart meters set the industry standard for advanced technology, cost effectiveness, breadth of features and benefits, and forward adaptability.

Now that collaborative approach working with meter manufacturers has been sufficiently successful, that announced last August we accelerated by one full year our time line for deployment, installation of those meters. And that means we expect to invest approximately $1.2 billion from 2007 through full system-wide deployment in 2012. So that's the foundation at Southern California Edison.

Let me turn, again, to the diversified growth plan at Edison Mission Group, and I'll be brief. We'll include in that plan development of new generation facilities, including renewable, natural gas fired and clean coal projects. During 2006, the growth initiatives progressed in three principal areas.

First, we substantially increased our prospects in wind generation. Edison Mission Group placed five new wind projects comprising 342-megawatts into construction during 2006. Of potentially greater significance, we have now secured exclusive negotiation rights through joint development agreements on approximately 2600 megawatts of wind development projects in 13 states.

Not all of these will meet our investment criteria or result in operating wind farms, but the pipeline is promising. Wind projects diversify our generation portfolio, provide favorable cash flows and increase the percentage of our power contracted in long-term agreements.

Second, we advanced the environmentally significant carson hydro project. Together with our partner BP, we are developing a hydrogen-fueled power plant that would be the first of it's kind and provide between 400 and 450 megawatts of electricity in the heart of the Los Angeles Basin, where our new electricity sources are needed.

In 2006, we won a $90 million federal tax credit for the project in the competitive process through the U.S. Department of Energy. The target operating date for the Carson Plant is 2012 to 2013. Much remains to be done before we can commit finally to the large capital investment that this very exciting project will require.

And then lastly, Illinois Governor Blagojevich and his administration committed to work with us towards the end of last year in November on commercially reasonable terms for the development of up to 400-megawatts of additional wind energy projects and one or more clean coal projects in the state. Work is under way to turn that commitment into the necessary foundation for investments.

A few comments on environmental issues. Environmental considerations intensified in 2006, as a driver of current costs, and future projects, prospects in the electricity business, certainly underscored by the recent TXU acquisition announcement.

Last December at EMG we entered into a very important environmental agreement with the State of Illinois. Some of you know about this and have followed it fairly closely. The agreement charts a long-term course for installing new pollution controls for nitrogen oxide, sulphur dioxides and mercury emissions at our Midwest Generation fleet of coal-fired power plants beginning in 2008 and continuing through 2018.

Subject to state regulatory approval, that agreement provides more certainty about future regulations and emission allowances, allows us to phase in pollution control projects over a reasonable timeframe, and offers full optionality in determining plant by plant whether to make environmental retrofit investments or cease plant operations beyond the agreed to date. We'll make those decisions on economic terms as the dates are reached.

Then, as you know, EMG also operates one large coal-fired power plant in Pennsylvania and new mercury rule has been adopted there this past month. We expect that our Homer City plant in Pennsylvania can achieve compliance with this new rule by the 2010 deadline.

So in short, and let me stop with this and maybe a comment on the TXU matter, but the results of 2006 mean most importantly for us we believe that our Company has excellent prospects for large scale growth over the next 5 to 10 years.

And let me just say something about the TXU acquisition. We're all following reporting and reports on it. I'll simply say this at this point. Any time major investors and banks do something of that scale and value in our industry, we look upon that favorably.

Our business, our strategy is not the same as TXU's, but the scale of our growth prospects have some similarity with what they had foreseen. So we will simply at this point take the TXU acquisition as offering an indication of special value potentially in our business as well.

All right. I'll stop there and ask Tom to go into greater detail on the 2006 performance.

Okay. Thank you, John, and good morning to everybody.

To make things-- this earnings review easier to follow, there are five supplemental charts at the end of our press release and I'll be referring to these charts throughout my discussion.

Charts 1 and 2 reconcile our core or operating earnings, which exclude discontinued operations and other non-core items to our reported GAAP earnings for the year and for the fourth quarter. Charts 3 and 4 include key operating and hedging information on our merchant fleet. And finally, chart 5 covers our 2007 earnings guidance.

I also want to remind you that we filed our annual 10-K's this morning, which provide you with more detailed information on the Company.

Now, moving to Chart 1, EIX reported consolidated earnings of $3.58 per share for 2006, compared to $3.47 per share for the same period last year. That's an increase of $0.11 per share.

Total core earnings for EIX were $3.07 per share for 2006, compared to $3.13 per share for 2005. That's a $0.06 per share decrease.

Now, the increase-- let me comment on these results relative to the guidance that we had after 2006. Core earnings were $0.16 per share higher than our guidance given last November, and our reported earnings are $0.39 per share, higher than that guidance also.

Now, the increases over guidance resulted from several favorable events that occurred right at year end. First, gains from several infrastructure fund investments were closed, as well as some asset sales at Edison Capital, and also the resolution of several tax-related matters that impacted both SCE and MEHC.

Now, let's look -- take a look at each of the Company's core results. SCE's core earnings for 2006 were $1.89 per share, compared to $1.82 per share for the same period in 2000. This $0.07 increase, primarily reflects the impact of higher net revenue from the implementation of the 2006 general case decision. That was a positive $0.11. And the full year of operation from our Mountainview Power Plant contributing additional $0.09.

Partially offsetting these increases were a higher effective tax rate in 2006 and lower other income. Turning to EMG, core earnings were $1.30 per share in 2006, compared to $1.42 per share in 2005. That's a $0.12 per share decrease.

MEHC's earnings were down $0.14 per share. And Edison Capital's earnings were up $0.02 per share.

MEHC year-over-year performance was predominantly shaped by the post-Katrina decline in both natural gas and wholesale power prices, also relatively mild weather and less volatile transmission congestion, which impacted our trading opportunities. MEHC's lower earnings resulted -- resulted primarily from lower margins at Midwest Generation, down $0.24, higher income taxes, impacted by $0.10, and lower EMT trading income impacting us by $0.13.

Now, although EMMT's income of 130 million last year was lower than the prior year, it did rank as the second best year in terms of performance for EMMT. Now, these decreases were partially offset by lower interest costs and higher interest income contributing $0.11 and unrealized gains under FAS 133 of $0.23. This reflects unrealized gains recorded in 2006 of 39 million and unrealized losses recorded in 2005 of 35 million.

Now, FAS 133 unrealized gains and losses reflect the non-cash impact of changes in forward power prices on hedges that do not qualify in full for hedge accounting. We present this information in the 10-K under market risks, in the section entitled accounting for energy contracts. We do this to assist you in isolating the impact on earnings related to these non-cash accounting entries.

And as we implement our hedge program and take our hedges out longer, this may have continuing large effect, depending upon where forward power prices move. Also as part of EMG, Edison Capital's core earnings were up $0.02 per share, mainly due to lower net corporate interest expense, lower overhead and gain on the sale of an affordable housing project, collectively about $0.09 per share.

These favorable items were partially offset by $0.07 per share decrease in gains from our global infrastructure fund investments. Non-core items for the year contributed $0.51 per share. As we continue to resolve contingencies, many of which are associated with the energy crisis.

SCE had a positive impact of $0.49 per share from the resolution of the regulatory matter, generator settlements and a favorable settlement regarding the apportionment of revenues for state income tax purposes. EMG's core items totaled $0.02 per share, mainly due to gains from discontinued operations.

That's $0.30 per share, largely because of the settlement of what we will call the bankruptcy of our Lakeland projects in the UK. This was partially offset by early debt extinguishment costs of $0.28 per share related to the refinancing done at mid year at EME.

Now let's go to Chart 2 and we'll factor -- we'll focus on the fourth quarter. Factors effecting earnings in the -- for the fourth quarter were essentially a reflection of the full year with the Katrina effect being the most pronounced in this period.

Consolidated earnings were $0.87 per share, up $0.04 over 2005, and core earnings were $0.65 per share, down $0.06 compared to the same period last year. SCE's earnings were up $0.05 on higher net revenue from the general rate case and the Mountainview operations.

And Edison Capital was up $0.12 on gains from it's infrastructure fund investments and the asset sale I mentioned earlier and lower taxes. These increases were more than offset by the lower results at MEHC, down $0.23, mainly from lower margins at Midwest Generation and lower trading income.

Non-core items contributed $0.22 per share, $0.10 higher than 2005, mainly due to the resolution of the state tax apportionment issue and MEHC's gains from discontinued operations.

Turning now to Chart 3, I'll provide an update on Midwest Generation and Homer City's operations. Operating performance at our Midwest Generation plants, as measured by availability and forced outage rates, was essentially the same in 2006 as 2005. The availability was just under 80% in both years and the forced outage rate was about the same at slightly less than 8%.

The generation was 28.9 terawatt-hours in 2006, compared to 31 terawatt-hours in 2005. Slower generation was driven largely by market conditions, which in part reflects the milder weather and lower market prices experienced in 2006.

Homer City's generation 2006 was down from 2005, as indicated in Chart 3, mainly due to the transformer outage at Unit 3 in the early part of the year. The transformer outage effected both availability and the forced outage rate. We were able to recover a portion of the costs associated with this outage through insurance.

Moving to the price information related to Midwest Generation and Homer City, the average flat price for energy at NIHub declined nearly 11% during the year to $41.42 per megawatt hour. The average flat price for energy the Homer City buspar declined 17.6% to $45.15 a mega-watt hour.

The average realized price in 2006 which takes into account our hedge contracts was $46.19 at Midwest Gen and $48.02 per megawatt-hour at Homer City, both of which were measurably above market prices that occurred during the year and higher than 2005. In short, our hedge program wasn't effective in mitigating the overall declining market prices during the year.

Fuel costs at both Midwest Generation and Homer City reflect scheduled price increases and the expiration of some lower price contracts, and were in line with our expectations.

As indicated on Chart 4, we have hedged about three quarters of our generation for 2007 and about 60% for 2008, both of which are at about the same levels we discussed in our third quarter call.

Lastly, on fuel, Midwest Generation entered into a contract to purchase additional coal in February, about 9 million tons in 2008, 6 million tons in both 2009 and in 2010. This increase in the amount of coal under contract now substantially matches our generation hedges for 2007 and 2008.

And finally, on Chart 5, we are affirming the 2007 earnings guidance from November of last year of $3.05 to $3.45. That range.

And although power prices have been quite volatile in the early part of the year, down substantially in January and then up again in February on the colder weather, our forward power prices looking today are essentially the same as they were, as those that were embedded in our November guidance. And so we feel comfortable that the guidance that we issued then is still good today and we are affirming that.

That wraps up my discussion. Now we'll move to questions.

(OPERATOR INSTRUCTIONS)

The first question comes from the line of John Kiani with Deutsche Bank. Please proceed.

Good morning, John.

John, can you give a little more color on your comment on the TXU transaction from earlier this week, please?

Probably isn't a lot more that I can say about it. It's a striking transaction, largest, as you know, private equity transaction announced to date. TXU, as I said, has had a different strategy than we have. We like our strategy.

We like what we've been able to accomplish under it, but the feature we think of our business that stands out is that our business requires challenges to make very substantial growth investments both in our utility and in our unregulated power generation subsidiary, and we like having these, these large prospects. They certainly challenge us to do everything we can do using the skills that we have.

I think TXU had that feature in common with us. So very substantial growth prospects, substantial growth ambitions. That may be where the similarities end, but it never hurts to see others recognize large value for growth and business opportunities in the electricity sector.

We like that.

Okay, thanks.

And then on Edison Mission Group, can you all give a little bit more color? I know you touched on it somewhat in the opening comments on the wind business and kind of where you expect to stand at the end of '07 and then what your outlook is beyond that, especially considering the fact that the production tax credit was extended at this point for one year and potentially for even longer based on some legislation that's currently out there.

John, it's Ted Craver. I'll give you some highlights here.

The renewables business in general, but certainly the wind business within that, is our primary focus for growth. We see pretty substantial opportunities there, largely driven by the increase in RPS requirements in the various states. What we have been primarily focusing on in the last couple of years is really developing a pipeline and roughly speaking, we have around 2600-megawatts in our pipeline.

We really define that as projects that are covered under some sort of a joint development agreement to give us exclusive rights to those projects. Certainly not all of those are going to get done.

They are not going to go to financial close and construction, but that's kind of the feeder stock for our growth over the next few years here.

The other piece is securing turbines. We've done a lot of work on that in the last year or so to make sure that we have access to sufficient turbines to really build out the portfolio.

We had some good successes on getting projects done last year and as we move into 2007 and 2008, which are both years currently covered under the PTC's, we expect to see that growth accelerate.

Thank you.

You're welcome.

Your next question comes from the line of Dan Eggers with Credit Suisse. Please proceed.

Hi, good morning.

On the So-Cal Ed talking about the 12% growth trajectory, is that more formalization of AMI and some of the transmissions investments, or are you-- have you found some more places to put capital that we want talked about previously?

I'll ask John Fielder in responding to that. I picked our four areas.

I think the four are the strongest areas, so we're talking there just inherent large scale growth in our service territory. We have four of the fastest growing counties. They are large counties, four of the fastest growing counties in the United States in our service territory, so keeping up with that is a challenge.

Then the State of California is appropriately mindful of the need to have a truly reliable network, a kind of state-of-the-art network since the power crisis of 2000-2001. I think that's been really, really prominent in the thinking of the leaders of the state from Governor Schwarzenegger on down, So we have both fast growth and a climate that says let's have California really lead in making infrastructure investments that are right and particularly in the electricity sector.

So that's a big factor. So that's number one, and that's really the largest. Now, then you have the AMI. You mentioned that.

That's a big deal for us and we like the fact that we think we've leaped ahead in finding meters that meet the needs of our system, which already had smart components to it. So we needed better meters than were on the market a year ago, or readily available at any time in the past. So that's still in demonstration, but we feel a level of confidence in it that we didn't have previously.

Then we talked a little about the continuing reliability needs in generation in Southern California and ours is a very peaky system and the enormous heat wave of last summer underscored the need for these new peakers, with quick start capabilities, so that PUC -- the governor was involved. PUC directed that we add those and we're adding five $250 million investment there.

Then we have this large, really for us and I think possibly across the Company almost uniquely large transmission expansion program. So if you take our existing invested capital and transmission, it's, as I recall, a little over $1 billion, on the books and we have a $4 billion expansion program and, again, in our life, some things trace back to the power crisis.

It was underscored during that power crisis that there just wasn't enough transmission capability to move power north and south in the state or to move it from the Southwest, where, including today, there is, there is a stronger power reserve capability than there is here in California. So we're expanding to the Southwest. That's a long process.

The permitting, we-- we use the expression maybe others have heard that when you build a power generating facility, you have one community that's involved and concerned about the effects. When you build a transmission line of several hundred miles or more, you involve potentially hundreds and thousands of communities and the permitting is considerable challenge.

So we made really nice progress in 2006 on the permitting, but the timing on that is one that, that we are always a little cautious about. If you look at the aggregate of all that, it adds up to the 12% compounded annually estimate, and we say and potentially more because if you actually look at the numbers on things that we'll be-- we have or will be filing for the numbers would add up to somewhat more than that.

But that's our best estimate. John, do you want to--

Only thing I would add, John, is in that five-year window that we're talking, about we also have a pretty significant investment in our nuclear plant.

We'll be replacing steam generators at both units in '09 and '10, which is approximately a $700 million investment during that same period that John's been talking about.

You said you were going to have to go in and get some adjustments for the regulatory approvals to get this extra capital layered in. Is this going to require more of a full blown GRC, or are you going to be able to do these as kind of unique case or some sort of addendum?

Yes, we can set out whether regulatory approvals are done and where they are not, but the most important thing for all of you to have in mind is that California's on this three-year cycle of general rate cases, so that means where we had a 2006 decision in the spring of the past year, we will have a so-called 2009 general rate case. That's in preparation now. That will be filed in the midpoint of 2007.

Then there's a process for the staff to look at it, determine whether it's fully complete with all the information they need. We'll work back and forth.

But we anticipate, and it's an important part of the outlook, that the 2009 general rate case will be a key to achieving these large investment authorizations that are needed to continue the reliability and strengthening focus on the infrastructure for us in Southern California.

So the capital's going to be covered by this next ERC versus the addendum you guys did with the the peakers for this summer?

The-- of course the largest part of the capital was the $5 billion authorized in 2006. But, yes, there will be another. But a number of these things, like, for example John mentioned the nuclear generators, are handled in -- the large scale -- the largest scale generation projects are handled at the PUC in separate proceedings.

So most the capital that comes for -- in the PUC in the general rate case is distribution investment. And that's the largest single part of our total investment. Then of course the larger scale transmission investments are under the jurisdiction of the federal energy regulatory commission.

So there you have both PUC authorizations for, call it the smaller transmission levels and the larger transmission is handled FERC jurisdictional proceedings. So there are a number of piece parts to the regulatory steps.

Dan, let me just add that the AMI advanced metering program would be handled in its own separate proceeding and that covers $1.2 billion.

Got it, thank you, guys.

The next question comes from the line of Paul Fremont from Jefferies & Company. Please proceed.

Thank you very much.

Back in October of 2004, the projected growth rate at MEHC was 0% to 5%. Can you give us a sense in terms of sort of a similar update on that business as to whether that growth rate would still apply, or whether you sort of would think different-- investors should think differently about that business?

I don't think about the numbers right there, but let me attempt--

The 0% to 5% was the contribution of MEHC to the EIX 8 to 12 growth rate.

Right.

But if you're just talking about MEHC, that was 7% to 48% is actually what we showed in the presentation. And really the lower values were mostly if we ended up with lower capacity values at the merchant fleet and the higher values where if we had higher capacity values of the merchant fleet.

As it turns out really, the 7% to 48%-- we've been in the higher zone of that and actually accomplished that within the first couple of years. From here forward, I think the growth rate is very much going to be driven on what we actually are able to do with new projects, new investments as opposed to relying solely on capacity values and energy prices.

So that's really the focus of our strategy from here forward, is new investments in generation, principally around the lines that John mentioned in his opening remarks, renewables, clean coal and gas development.

You mentioned new mercury rules in Pennsylvania is there sort of an estimated spending level to comply with those rules?

Roughly speaking in kind of $50 to $60 million range to be accomplished by July of 2009. We'll put ACI activated carbon injection units on 12 of our generating units in Illinois, and on two of the units, Unit 1 and 2 at Homer City.

And the specific for Homer City?

Well, Paul's question was specifically to Homer City.

Oh, I'm sorry.

I thought you said Illinois. Illinois would be 12 units of ACI in the 50 to 60 million range and Homer City, it's ACI on 2 units. It would be roughly in the $10 million range.

Okay.

And then can we get breakouts, specific breakouts for the fourth quarter infrastructure gain, the affordable housing gain. I think you sort of bundled that with another item for $0.09, and the trading contribution in the fourth quarter.

Yes, I-- let me have Mark Clarke break that out for us.

Yes, the increase in the global infrastructure fund was $0.05 and affordable housing was $0.02. And what was the other question, on trading?

Then the trading contribution for the quarter?

We'll get back to you on that, Paul.

And the infrastructure gain, I mean initially I think when you first started recognizing those in '05, you sort of characterized those as not expecting those to be recurring.

At this point in time, I mean are these-- should we look at these as sort of recurring in nature, or should we still look at them as unusual items?

Paul, we've been pleasantly surprised by the performance of those infrastructure fund investments.

But those funds are winding down. The remaining investment balance on the books is $67 million, and so in our guidance for 2007, we had $0.15 in there for Edison Capital and we think that's more reflective of kind of the ongoing nature of what it will produce.

And so we can't predict what might be coming out of those funds, but our position is not very large in the remaining-- our remaining investment position is not very large.

And, Paul, the contribution on trading retax, 20 million about in the fourth quarter.

20 million retax.

And the last question, just to make sure I'm reading this right, the 9 million of tons, the 9 million tons that you purchased in February should be added to the 17.2 in '07. These numbers should be added to the numbers that you're showing on the, in Chart 4?

Yes, that's correct.

Yes.

Yes.

The numbers in the chart are as of 12-31.

I'm sorry. The 9 million would be added to the '08 number?

9 million should be added to the 5.8 million tons.

And the 6 million added to the 5.8 as well?

Correct.

Just wanted to make sure I was reading that correctly. Thank you very much.

Okay, Paul.

The next question comes from the line of Paul Patterson from Glenrock Associates. Please proceed.

Yes, can you hear me?

Yes.

Yes.

I was just wondering if I could just follow up-- in terms of looking at 2007, your guidance remains unchanged, looks pretty much the same.

I just wanted to make sure, is trading pretty much, are you still looking at the same outlook for trading, is that 0? I think that's what you guys had before in your numbers. Is Edison Capital still around $0.15?

Any change in FAS 133 or anything that you're looking at? Is there any change I guess notably in terms of how-- what's driving earnings in 2007 than what you had in November?

No.

The fundamental driver was around forward power prices and I mentioned they are essentially the same as when we delivered that guidance. I mentioned that we haven't-- what was embodied in that was $0.15 for Edison Capital. We're not changing that.

Right.

And so--

Trading's still neutral, right?

And we're neutral on trading in there.

Okay, great. Thanks a lot, guys.

This is an uncharacteristically quiet group. Operator, this--

We do have questions waiting from the phones.

We have Jonathan Arnold from Merrill Lynch. Please proceed.

Good morning, gentlemen.

Good morning, Jonathan.

Couple things, one, on the utility, and this capital program, is there-- I was just looking, following up the 10-K and looking at the sequencing of the spending over five years. It looks like it's low 2 billions in '07, higher 2 billions in '08 and then getting up towards 4 and above in the three later years of the five-year plan.

And do you anticipate needing any external financing beyond the kind of, the data preferred options that you've talked about for the front end of the program as you go further out in time and if all of this gets approved?

No, we don't.

You know, the regulatory mechanisms that are in place for the utility are designed to be able to accommodate that.

Okay.

That was-- then my other issue-- I see you added some hedges at Homer City for 2009. At a average energy price of $71. Is that-- would you characterize those as around-the-clock type pricing or more of a peak, and how comparable would this kind of, the timing on the contract on the earlier periods?

Those would be on peak.

And say the '08 hedge is more of a balance? Peak to non-peak?

Yes, it would lean more towards peak, but there is, there is some off peak in there.

Okay.

So we shouldn't kind of think of a $10 uptick in that piece you've hedged in, kind of not fully comparable.

That's right. And of course we're fairly early in the hedging program for 2009 for Homer City.

Okay. Thank you.

The next question comes from the line of Jennifer [Bartelli] from Luminous. Please proceed.

Good morning, guys.

This is Michael Goldenberg.

Didn't sound like Jennifer.

I'm sorry. I'm patching in by mobile.

Couple of questions. First of all, on the TXU transaction, obviously investors see a lot of value in owning coal plants in the market where over 80% of the power is priced by gas on the margin.

So I was wondering if you can tell us where you-- at what-- in what year do you think the Illinois and Western PGM markets will reach similar levels of gas as a percent on the margin.

Hi this, is Ted.

I don't think you would expect to see Illinois really approach IRCOT-type levels for gas on the margins any time soon at all. It's dominated by nuclear and low cost coal, so I think it's unlikely you're going to see anything close to the IRCOT-type levels.

Are we talking 2009, '10, '11?

I think it would be past that.

And what about western PGM?

Really the same thing. A little more coal dominated than nuclear dominated. In general, there's much less gas on the margin in western PGM.

Secondly, I don't know, maybe you mentioned this. I didn't see it. As far as the IRS LILO/SILO debate, can you give us more color as to the nature of those discussions as to the timing of either a court case or settlement and what you guys are assuming there?

Well, I mean we provided the update in the K and, you know, we continue to work through the appeals process on those cases, to work through the appeals process on those cases, and we'll make a determination in terms of proceeding with litigation if we are unsatisfied with the results of our discussions with the IRS.

Okay, but any idea on timing of this?

We'll, we'll make a determination during this year on which way we're going to proceed.

Okay.

And thirdly, can you tell us a little bit more about your discussions as to the selection of the construction firms for your environmental -- environmental process in Illinois, how you're going about selecting company for mercury and going further for SCR scrubbers.

It will be a competitive process.

Are you close on the selecting those firms?

We're starting the RFO's for some of the early stage stuff-- this goes out for 10-plus years. But for the mercury removal work, we're going out with the RFOs now, but it will be several months before that.

How many companies are overall capable of doing this mercury? Are they a lot, or is it a limited subset?

There are certainly more than a couple.

Okay. Thank you very much. Good luck.

Thank you.

The next question comes from the line of Clark Orsky from KDP Investment. Please proceed.

Hello?

Yes.

Hi, had a question on Homer City.

I think maybe it was back in the second quarter Q, I think you said you basically kind of deferred making environmental upgrades because the costs were running ahead of plan. I'm just wondering where things stand now.

Okay.

Maybe just a little background first. Homer City has SCRs on all three units. It has FGD, or scrubber, if you will on, Unit 3. So the principal discussion is around whether or not FGDs make sense for Units 1 and 2 and at what period of time we might make that decision.

Because of the dramatic increase in the cost of FGDs, the whole EPC cost structure is dramatically increased. We deferred decision on installation of FGDs for unit 1 and 2. That remains the position we're in now.

In the near term, the principal focus on environmental retrofits will be on the installation of activated carbon injection for mercury removal on all three units, or on the Units 1 and 2. Excuse me.

In what timeframe would you be sort of forced to make a decision? Is it 2010, or-- to meet the 2010 deadline, I thought?

No, that's not, that's related to mercury, not SO2.

Okay.

And what's the deadline there?

Well, it's in the process of state implementation plans are in the process of going through Pennsylvania now for the care rule. So we don't have a specific hard and fast date to settle at this point, but probably somewhere in the 2015 range.

Okay. Thank you for that.

You're welcome.

The next question comes from the line of Terry Shu from J.P. Morgan. Please proceed.

Couple questions.

First, on the utility, John, when you talked about the higher rate base growth, the 12%, which is an increment I think over prior expectations, I apologize, I haven't had a chance to go through the 10-K.

But it looks like it ramps up because the rebase growth will be following the CapEx growth, which is not this year or next, but ramping up as we move towards latter part of the decade, into the next decade. Is that correct?

That's right, Terry.

You may recall that in our October 2004 strategic plan announcement, we foresaw then an 8.5% compounded annual growth rate over the full period and it was 8% for the year, as we have just been through, 2005, 2006. And this is a considerable step-up from that.

Right.

We've kept all of you apprised of what is a big challenge for us and that is to make these investments with substantially the skilled work force in the field, that we had at much lower investment in growth rates, but it's what California wants. It's what we believe is right and our people have responded.

So the level of investment in this PUC general rate case authorized category that was made, closed, gets on the books for 2006, for example, was 1.7 billion of the 5 billion for the period authorized in that general rate case, so it is a step up.

So when we plot it out, I mean we can basically use the CapEx numbers that you've provided and then kind of plot it out and see how rate base growth accelerates and make judgments about rate outcomes and such.

Have you done any preliminary forecast as far as rate impact on customers? I know there a various other assumptions that come into play. So excluding fuel, have you done any kind of analysis as far as the--

Yes, we have.

-- rate relief associated just purely with the rate base growth?

I understand the question. The answer is yes, we have looked at--

I gather it's moderate, right?

Yes, it is I'm going say quite moderate, but here's the important thing, Terry. Since there are large external variables. Let's just take natural gas prices, California, as you know, in general is a very heavily natural gas fired generation base. So customer rates are meaningfully determined by what happens to natural gas prices.

So what we've done is look at what we-- current forward natural gas prices, but those will certainly change over time. These investments come into a timeframe at which some other favorable things happen for our rates, like the rolloff of the very expensive, very high priced state power contracts that were entered into during the power crisis.

So there's some rolloff steadily through the period.

The short answer, as best we project it now, the effect on customer rates is quite modest.

Okay.

Second question, going back to Mission, I'm still a little bit confused. When you show the load requirement service contracts, that you, for instance, see $64 or so for '07 and '08.

What should we, when we do-- for modeling purposes in terms of the costs associated with it, when you-- when we have the generation output number and then you put in a price and costs associated with it, what is the net amount?

I think I've asked you that question before, Ted, and what do you net in terms of having those type of or the full service contracts as opposed to energy only?

Yes, the reason this is probably still a little confusing is we won't know what, if anything, we net from those until they have run their full course. That's because it isn't really a cost plus kind of concept.

You're having to project what you think the load shape is going to be. You're having to project what you think some of the risks are going to be that you can't hedge out. You have to simply price those risks.

And until we really run the contracts all the way through the period, we won't know whether we appropriately priced those risks or not. So you can't really do it on a-- here's the three components of costs. We've got those costs covered in one way or another, with offsetting hedges.

The reason for the confusion on my part is that I thought you had said that you are supplying all of the generation. So you're not buying from anybody.

It is your own generation, and therefore the cost is really an opportunity cost?

I think that part is correct. It's certainly going to cost us real dollars to buy coal shipment.

But that you know, because you have hedged that out. That's what I meant.

Not fully.

Okay.

No.

All right. Okay. Thank you very much.

You're welcome.

The next question comes from the line of Andrew Levi from Bear & Company. Please proceed.

Andrew, before you jump in, let me just say we're at the, we're at the end of the hour that we normally allot, so we'll do Andrew and one more and we'll try to be succinct. Then for the remainder of you, if there are questions, of course we would like to answer those and you know how to reach us.

But go ahead, Andrew.

Thanks.

Not to beat a dead horse, maybe not on this call, but I know you've kind of answered these questions before, but, you know, with the market not fully valuing your stock, I guess in my opinion, I'm just trying to figure out what your thinking is now.

You've answered this before, just on breaking up the company or an LVO. Obviously, you've addressed it in the TXU stem. But how do you try to get more value out of your stock based on the way the Company is set up and why not do it?

We like our strategy.

It has served us well, and if you believe there's more value in the stock, I encourage you to invest, as I do everybody else on the phone. We think there's good value here.

But what's your view on breaking up the Company?

That hasn't been our strategy.

Okay.

And that continues not to be your strategy?

We like our strategy, as I said.

Okay, great. Thank you.

There are currently no questions remaining from the phones.

All right.

Well, we thank all of you very much for your interest, and as indicated, please don't hesitate to call our Investor Relations group.

That closes the call.

Thank you.

Thank you.