愛迪生國際 (EIX) 2009 Q3 法說會逐字稿

Good morning. My name is Barb and I will be your conference coordinator today. At this time I would like to welcome everyone to Edison International third quarter 2009 financial teleconference. (Operator Instructions) I would now like to turn the call over to Mr. Scott Cunningham, Vice President of Investor Relations. Thank you Mr. Cunningham, you may begin your conference.

Thanks, Barb, and good morning everyone. Our principal speakers today will be Ted Craver, our Chairman and CEO and Jim Scilacci, our Chief Financial Officer. Also with us to participate in the Q&A session are other members of the management team.

The presentation that accompanies Jim's financial review together the earnings press release and our third quarter 10-Q filings are available on our website at www.edisoninvestor.com. During this call we will make forward-looking statements about the financial outlook for Edison International and its subsidiaries and about other future events. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our third quarter 10-Q and other SEC filings. We encourage you to read these carefully.

The presentation also includes additional information including certain outlook assumptions, as well as reconciliation of non-GAAP measures to the nearest GAAP measure. When we get to the Q&A, please limit yourself to one question and one follow-up. If you have further questions, please return to the queue so we can give as many of you as possible an opportunity to ask a question.

With that, I'll turn the call over to Ted Craver.

Thank you, Scott. Good morning, everyone. This morning we reported third quarter GAAP earnings of $1.23 per share and core earnings of $1.09 a share. We are essentially reaffirming our earnings guidance for the year, but with the summer behind us we are narrowing our guidance range. We now expect core earnings to be in the range of $2.95 to $3.15 per share.

Overall we're pleased with the results of the quarter and what we've been able to accomplish thus far for the year. We've tried to focus on the things we can control with particular attention to superior execution. I'd like to highlight some of the more noteworthy achievements that helped us produce solid earnings in spite of the worse than expected economic conditions and the sharp declines in financial and commodity markets.

Let me start with our progress in dealing with some of our greatest challenges. Weaker than expected commodity prices and heightened concerns about public policy pressure on coal generation have worked to depress the implied value for Edison Mission Group. It appears no value, indeed probably negative value, is being assigned to this business currently by the market. We know the current valuation reflects investor concerns about the forecasted amount of capital needed to meet more stringent NOx and SO2 emission requirements in the 2012 to 2019 period and the uncertainties around potential carbon regulations.

I believe negative value is unwarranted since we have made it clear that given the high level of uncertainty around the coal fleet, Edison Mission Energy must live with the existing level of capital EIX has committed to it. We view the current valuation as a potential opportunity if we can resolve the uncertainty around the capital needs of the coal fleet and improved liquidity at EMG and finally build value in the renewables portfolio.

Let me discuss recent progress in addressing these three areas. First, EMG has been busy developing alternative control options to meet the Illinois NOx and SO2 emissions requirements. Technical tests have encouraged us that we have real potential to achieve the state's emission targets at a significantly lower capital cost. EMG has more work to do to fully understand the financial trade-offs of these alternative approaches, and we must conclude they work with the regulators and legally. We have largely concluded SNCR's are the optimal means of meeting the more stringent NOx requirements starting in 2012, which our best estimates suggest will save us roughly $350 million to $400 million in capital expenditures. However, we still have more work to do on the alternative SO2 approaches and that work will continue into next year.

Second, we wanted to improve liquidity by reducing cash outlays in 2009/2010 at EMG. I will save the specifics for Jim to discuss, but we have successfully negotiated payment deferrals or financings with our wind turbine suppliers thereby significantly improving liquidity.

Third, we wanted to prudently continue expanding our renewables business by placing our committed wind turbines into good renewables projects where we could obtain financing on the strength of securing long-term PPA's. In October, we placed two new projects totaling 390-megawatts into construction in Illinois and Texas. As evidenced by these two new projects, we are once again seeing utilities making new contract commitments for renewable projects and banks actively marketing project financings.

EMG now has 27 wind projects in service or under construction in ten states with a combined generating capacity of nearly 1,600-megawatts. The near-term strategy remains focused on utilizing existing turbines in new projects. We have several other renewables projects with PPA's either in negotiation or under regulatory review to utilize the remaining turbines under commitment.

Staying with the growth theme, let me cover progress at Southern California Edison, starting with our large transmission projects. In addition to the Tehachapi Renewables line, SCE has two other major transmission lines currently in various states of construction and regulatory approval. We thought by this date we would receive CPUC approval of the revised Devers-Palo Verde Project now referred to as the Devers Colorado River Project but the decision was held until the next meeting. This project, if approved, will support important renewable generation and has an estimated cost of $637 million.

SCE also filed an application with the CPUC and a request for incentives at FERC for the $464 million Eldorado-Ivanpah Project. This project located near the California - Nevada border will also allow access to important solar and wind resources, some of which already have contracts.

Another major capital project underway at SCE is the steam generator replacement at San Onofre Nuclear Generating Station with the first two of the four steam generators on-site and expected to be placed in service by year-end. The project is intended to enable San Onofre to operate until 2022, the end of its initial operating license period, and beyond if license renewal proves feasible.

A final update on growth projects involves SCE's 250-megawatt solar rooftop program. SCE expects to invest $817 million in this program from 2009 to 2013. We recently placed our second utility owned rooftop project into service and are working on our third. Southern California Edison is currently awaiting California Public Utilities Commission approval to issue the first cycle of solicitations for rooftop solar power purchase agreements for an additional 250-megawatts of projects to be developed by IPPs.

There were operationally-focused achievements in the quarter as well. At EMG, the focus on generating unit availability is starting to yield improvements in reduced forced outage rates for the coal fleet. The third quarter equivalent availability averaged about 91% for the coal fleet. Necessitated by the exceptionally low off-peak prices this year, EMG has done considerable work on developing operational techniques to mitigate negative margin off-peak hours. EMG has also managed the remediation of the Suzlon cracked turbine blades which was completed this quarter. These Suzlon projects are now operating inline with the rest of the wind fleet.

In September, SCE achieved a major milestone when it installed the first smart meter as part of its $1.2 billion Edison SmartConnect capital program. While this is a growth project as well, I chose to highlight it as an operational achievement because of the enormous undertaking to install 5.3 million smart meters by 2012. Edison's SmartConnect is a key step in transforming the electric system to a smart grid which will literally change the way Edison does business.

This quarter, Southern California Edison achieved some key milestones on the regulatory front. In September, the FERC approved a settlement of SCE's 2009 base transmission rates which went into effect March 1, 2009. It also accepted SCE's proposed 2010 base transmission rates, subject to refund and settlement procedures to be effective March 1, 2010. The 2010 proposal would increase SCE's revenue requirement by $107 million. These increases are critical to support our renewable and system reliability transmission.

In October the CPUC approved our two-part request to forego an expected 2010 cost of capital increase under the annual adjustment provision of our three-year mechanism and extended SCE's capital structure and rate-of-return through 2012, absent a future triggering of the annual adjustment mechanism. This approval provides important stability and predictability for both our customers and our investors.

I would like to conclude with a few remarks about two key public policy items that are pending and that can have substantial impact on Edison International. The first is comprehensive national energy legislation, including potentially cap and trade provisions. Edison International has been a part of the EEI CEO Climate Change Task Force effort and strongly supports the comprehensive climate change package developed through that effort which includes the so-called 50-50-50 allowance allocation formula for the electric industry.

Edison International went the additional step of publicly supporting the Waxman- Markey legislation which the House passed in large measure because HR2454, as it is called, included a well-balanced and appropriately flexible National Renewable Energy Standard and Energy Efficiency Standards. The Waxman-Markey cap-and-trade language also included much of the EEI climate change proposal, including the 50-50-50 allowance allocation formula. We were hopeful the Senate bill would fix some of the deficiencies in the House cap-and-trade provisions, but frankly it is too early to tell if that will come to pass.

A central principle for EIX is that we believe we need to address climate change and eliminate the ongoing uncertainty around the cost of carbon regulation. Long periods of uncertainty are deadly for capital intensive industries like the electric power business and must be resolved in order to support the necessary transformation of this industry to a cleaner, more efficient infrastructure and allow capital formation to proceed.

Strongly related to the national energy debate is the move within California to increase the percentage of customer load served by renewable generation from 20% to 33%. The various bills proposed in the recently concluded California legislative session for moving to 33% had several issues. Less because they called for increasing the percentage to 33%, but more because the provisions for getting there were overly restrictive and costly for consumers and increased risks to service reliability. Governor Schwarzenegger vetoed this legislation and issued an Executive Order to increase California's renewable energy goals from 20% by 2010 to 33% by 2020 and has directed the California Air Resources Board to implement this policy.

Achieving a 33% renewable portfolio by the year 2020 is highly ambitious given the magnitude of the infrastructure bill that required and the slow pace of transmission permitting and approvals. According to a study performed by the PUC, the 33% goals will require $115 billion in investment statewide, including about $12 billion in transmission to access renewable resources. We will strongly urge the state to study the renewable energy provisions in the Waxman-Markey bill and in Senator Bingaman's energy bill as they craft their 33% provisions. We can get to 33%. But we need to do it in a thoughtful way that balances our need to transition to more renewable resources with the cost and reliability concerns of electric customers.

With that, I'll turn the call over to Jim Scilacci.

Thank you, Ted. And good morning, everyone.

Today I will discuss the following items; our financial and operating status, our hedge and liquidity positions, developments with EMG's wind program, an update on SCE's capital spending and rate-based forecast and our updated guidance. Let's get to the numbers now.

We've introduced two new slides this quarter to better focus on the key drivers for the third quarter results at SCE and EMG, as well as key developments during the quarter, many of which Ted has already mentioned. The appendix includes our normal more detailed variance analysis for the quarter and year-to-date.

Turning to page two of the slide presentation, EIX reported, as Ted said, third quarter 2009 GAAP earnings of $1.23 per share compared to $1.33 for the same quarter last year. Excluding non-core items, EIX core earnings came in at $1.09 per share or $0.37 lower than the third quarter of 2008. Within these results, EIX's parent company (and other) came in $0.03 favorable this quarter compared to the same quarter in 2008 due to slightly lower income taxes, G&A costs and less impact of participating shares on our basic EPS calculation. Participating shares relate to the vested stock options that earned dividend equivalents.

Turning to page three in the deck, on a GAAP basis SE earned $1.06 per share during the third quarter 2009 compared to $0.72 last year. The $0.14 non-core item in 2009 is the impact from receiving regulatory approval to transfer our Mountainview Power Plant to utility rate base. Previously Mountainview was built under a separate SCE subsidiary selling to the utility under a long-term contract and certain financing costs were recovered and recognized over time, mainly equity AFUDC. With the transfer to SCE rate base these costs are now capitalized under cost-of-service rate making. This is a one-time, non-cash benefit.

SCE's third quarter 2009 core earnings were $0.92, an increase of $0.05 over the same quarter last year. The increase is primarily driven by $0.13 from increased operating income, as a result of our 2009 GRC decision and a $0.04 favorable earnings from costs incurred in 2008 from ballot initiatives. These favorable variances are partially offset by $0.12 of higher income taxes, primarily from two items. First, about half the variance was from our annual trueup of estimated taxes at the actual filed tax return recorded in September of each year. And 2008 recorded a positive tax return trueup of about $0.03 per share and in 2009 recorded a negative $0.03 per share.

Second, in the third quarter of 2009 we lowered our estimated of a certain property related flow-through tax deductions. Turning to EMG on page four, GAAP earnings were $0.19 per share during the third quarter of 2009 compared to $0.66 last year. Core earnings were also $0.19 per share or $0.45 below last year.

Core earnings declined primarily from lower gross margins at Midwest Gen and this can be broken down in a couple of categories where lower average realized energy prices and lower generation, higher fuel costs, primarily from annual NOx and Mercury removal expenditures. And these things were partially offset by higher capacity revenues at our coal plants. The lower gross margins were partially offset by reduced plant operating expenses. Mild summer weather and the ongoing impact of recessionary conditions contributed to the lower electrical demand in PJM.

On a quarter-over-quarter basis, earnings were lower by $0.37 per share for the merchant coal fleet, broken down roughly $0.27 at Midwest Gen and $0.10 for Homer City. Trading revenues at EMMT were off $0.05 and the big four natural gas projects were $0.04 lower. There was $0.01 improvement from lower G&A. Although, EMG's renewable portfolio was not an earnings contributor in the third quarter of 2009, primarily from mild wind conditions, it remains an important factor in our year-to-date results.

Turning now to the year-to-date earnings on page five, which we won't get into much detail here, I'll just make a couple of points. The detailed analysis of the year-to-date results are included in the appendix.

SCE's year-to-date core earnings were $2.17 or $0.36 above the same period last year. As I mentioned, most of this is driven by higher operating income. On a core basis, EMG earned $0.55 per share compared to $1.47 for the prior year. Overall the reasons for the lower year-to-date earnings are essentially the same as the third quarter results.

Pages six and seven provide key operating statistics for Midwest Gen and Homer City. Ted has already mentioned the improved availability and forced outage rates. Generation was slightly lower at Midwest Gen and more so at Homer City primarily reflecting the weak economy and mild summer.

Turning now to page eight, since the end of the second quarter we added significantly to our hedge position. On the power side, we hedged an additional 5.6-terawatt hours for 2010 at Midwest Gen and about 1-terawatt hour for Homer City during the third quarter. That brought our 2010 hedge position to 12.6 terawatt hours at Midwest Generation and 3.6-terawatt hours at Homer City as of September 30th. In October we added an additional 7.5-terawatt hours of mainly off-peak 2010 hedges at Midwest Gen. We took this action as a hedge against low off-peak prices and the potential for negative margins which we experienced this year. The off-peak hedge volume should enable us to operate at minimum loads and avoid placing units in reserve shutdown as was done this year to mitigate the impact of negative margins. This brings our 2010 power hedge position to about 20-terawatt hours at Midwest Gen.

On the fuel side, and as we mentioned in the last quarter call, we added about 5.4 million tons of coal at Midwest Gen for 2010, 9.8 million-tons in both 2011 and 2012. We also added to our Homer City coal position purchasing 3.7 million-tons in 2010, 2 million-tons in 2011 and 1.2 million-tons in 2012.

Overall we felt it was important to step up the level of hedging to lock in more of our gross margin, protect against low off-peak prices and move closer to a hedge neutral position for 2010.

Turning now to liquidity, on page nine, most of you will recall our Company significantly drew down on our credit facilities in the third quarter of last year. With the return to more normal financial conditions, SCE and EIX substantially paid down their lines during Q2. EME and Midwest Gen started paying down their lines during Q3 and now all our Companies are back to normal operating utilizations. Overall, liquidity remains strong across our Companies.

Now moving onto EME's wind turbine developments, which is on page 10. Throughout 2009 we have worked to preserve capital at EMG by focusing on a selected growth strategy, primarily on completing projects under construction, developing sites for our existing wind turbine commitments and securing projects and better financings for our wind fleet. Through the end of October we have made good progress on our overall wind program. As we mentioned before and Ted has highlighted, we completed project financing in June for three of our existing projects and in July we completed the construction of the 100-megawatt High Lonesome project.

As of September 30, we had 948-megawatts of turbines available for future projects. As of October 31, we now have reduced the turbines available for new projects to 512. This was achieved by putting 240-megawatts in construction in our Big Sky project in Illinois, another 150-megawatts into construction at the Cedrow Hill project in Texas, and converting 46-megawatts from firm commitment to an option to purchase. We are also in advanced development on three projects that, if completed, would use the majority of our remaining available turbines.

We've also provided a comparison of wind commitments, both expected construction expenditures and remaining turbine payments on the unallocated turbines as of June 30 and September 30. From the information provided you can see our progress in deferring payments from 2009 to 2010. You will also see a reduction in remaining payments on unallocated turbines as remaining payments for newly allocated turbines, turbines that are going now into construction. Construction expenditures also increased as an additional balance-of-plan costs are added for the 390-megawatts now in construction.

While we're maintaining our financial discipline, and only advancing projects from development to construction where we believe there is strong probability of financing. For the two projects in construction in October we closed the approximately $200 million project financing for the Big Sky project. We have also initiated discussion with bankers to project finance the Cedrow Hills project.

As we near the end of construction, we will then evaluate using PTC's, ITC's or cash grants for these projects. All in all [Ron Segur] and his team has made much progress in our wind program this year.

Turning now to SCE for a minute, I want to update you on your latest thinking on the utilities five year capital spending and rate-based forecast. This is on page 11. You can see our overall five-year capital spending program up $20 billion in our base case scenario and $16.8 billion in our low case.

We have updated our capital spending numbers, primarily transmission, to reflect longer anticipated lean times and the removal of the Arizona portion of the DPD2 line. Overall, we have lowered our five-year transmission spending forecast by $1.3 billion. Partially offsetting this reduction are additional distribution and technology-related investments to support our growth programs, which are contingent upon regulatory approvals in 2012 GRC or other regulatory proceedings. The net reduction in our five-year forecast is about $600 million. We have also narrowed the range between the base case and the low case from 18% to 15% reflecting the updated transmission forecast.

As shown on page 12, we have also updated the five-year rate base forecast for these changes, as well as the 2009 FERC rate case settlement that Ted mentioned earlier. The FERC settlement is the primary reason for the $300 million increase in our 2009 rate base forecast.

Lastly, turning to guidance now, we narrowed the guidance range for GAAP and core earnings per share, leaving the overall midpoint of each unchanged at $2.33 on a GAAP basis, and $3.05 per share on a core basis. We now see a slightly different mix on the earnings contribution at the midpoint of each guidance range.

We have increased our SCE earnings midpoint guidance by $0.06 per share to $2.55. This reflects the impacts of the 2009 rate-case settlement and interest-related benefits on our global tax settlement which has and will allow SCE to defer some previously planned long-term debt and preferred financings. We are continuing to assume $0.03 in energy efficiency earnings. We decreased the holding company forecast EPS based on their year-to-date experience. Together the increase at SCE and holding company is partially - - is offset by lower guidance at EMG.

We have updated our forward power commodity price assumptions as of September 30. We have lowered our outlook at EMMT trading revenues to $50 million to $75 million compared to our prior rage of $50 million to $100 million. And we expect $10 million less in impact from the recontracting of the big four gas fire projects with an updated estimates of $35 million to $45 million pretax reduction. Finally, consistent with our normal practice, we expect to provide earnings guidance for 2010 when we report full-year results on or about March 1 of next year. That concludes the third quarter review. Operator, we're ready for Q&A.

And thank you, sir. (Operator Instructions) And our first question comes from Dan Eggers. Please state your company name.

Hey, Credit Suisse, good morning, guys. Ted, could you share, shed a little more light on the progress that you're seeing on the environmental remediation options on the Midwest Gen fleet and beyond the SNCR savings what else - - what other room you see for, your know, reducing that big bucket of money [you can trigger].

Dan, did you address that to me?

Yes, sure. Anybody can answer it, I suppose.

Okay, all right, frankly, you are breaking up little bit so I was not sure that I really caught all of the pieces. I'll just take a first swipe at it and then turn it over to Ron and Jim. Fundamentally, what we've been trying to do with all the work on these alternative compliance approaches is to see if there's a way to meet the more stringent NOx and SO2 requirements but in a less capital intensive way. And I think we've mentioned before some of these different approaches. Of course first you have to make sure they work technically, and then secondly you have to make sure you understand what the trade-offs are. And in some cases the trade-off is between capital expenditures, lower capital expenditure, but higher operating expense. So that's where a lot of the work is going on right now, particularly on the SO2. And then finally we want to make sure that any alternative compliance program that we come up with is going to really work from a regulatory standpoint.

So the point really being, we want to make sure that they are durable and that we don't head down a path of a different technology or a different approach, only to find out it's got difficulties on the regulatory or legal side. So those are the conditions that we're working through. I think as I said in the remarks pretty clear where we are on the use of the SNCR's as the alternative for meeting the NOx requirements and those are the first installations that would have to go in. We still have more work to do on the SO2 side.

What should we assume the timing is going to be for the SNCR spending? And should we assume that the $350 million or $400 million of savings, those are pretty short-dated relative to your previous expectations?

Well, it has to be installed by January 1, 2012. I mean, that's when we have to meet the tougher NOx requirements. The SNCR's require a lot less work, which is reflected in the lower capital costs, so we have more lead time. But fundamentally we're getting to the point next year where we would have to start making some installations.

And based on the forwards today you think that the SNCR investments are economically sound decisions?

Well, we believe at this point that's probably likely to be the case. But, again, these things go ultimately as a package. Any investment that you make in the unit you have to make sure that you can get that investment back out. And that you have enough run time with the unit to get the investment back out. Those kinds of investments are made more difficult when you have the level of uncertainties around future environmental regulations, including potentially carbon. So at this point I would say that's likely to be the direction we go. But we haven't really come to a final, firm conclusion.

Okay. Thank you.

This is Jim, just one additional bit of information. The savings that was quoted was relative to our original plan. In the original plan, just for reminder, we actually put this information, I believe, in our 10-K at the end of 2008, was two FCR's, the power station, I think we quoted in there approximately $500 million. And so the savings is relative to that.

Next question.

And the next question comes from Greg Gordon, please state your company name.

Thank you, Morgan Stanley. Good morning.

Good morning.

At what point during the year next year do you think the 390-megawatts of projects in the wind business that you put under construction will be spinning? So when will - - so I can think about an annualized earnings contribution.

What's going to happen here it is going to take most of year to construct the two projects, both the Big Sky and Cedrow Hill. So you will see very little benefit from those two projects until there will probably be a very little timing at the very end of the year. But you are picking up a little bit of a benefit from the High Lonesome project. The projects that are in construction this year, then will fall into next year.

And the tax treatment that you will be electing on the 390-megawatts?

I view that as -- and the way we think about it as a financing decision. And we're going to assess that as we get closer to the end of construction. So we're juggling between PTC's, ITCs and cash [FRAN]. And one of issues we're also trying to figure out with the cash FRAN, will the state of California tax that as taxable income here in the state. And so there are some trade-offs there in terms of what we're evaluating but we're still looking at that now, haven't come to a conclusion yet.

If you took the convertible ITC, would you book it all in the first year or would you amortize it?

We're going to defer it.

Would you defer and amortize?

Yes, we would amortize it over time.

Okay, thank you.

Thank you.

And the next question comes from Jonathan Arnold, please state your company name.

Deutsche Bank.

Hi, Jonathan.

Good morning, thanks. I have a - - my first question was on your coal contract for transportation at Midwest Gen. Can you just talk about how you're thinking around timing, when you might seek to renew that or otherwise given everything else you have in the air on the environmental side and maybe an opportunity in the market on that front today in this economy.

What we'll do there, that's one of the many factors that we're working through right now. But we're not going to comment (inaudible) when we're going to start negotiations. But it's an important factor in thinking through the Midwest Gen environmental upgrades in terms what it is going to cost to bring the coal to Midwest Gen and it goes to the economics and the cost effectiveness of some of these decisions. So it's an important element overall and we'll just report on it when it's appropriate.

You are not in negotiations currently or not saying, there's "no comment?"

I'll just say no comment.

Okay. Could I ask one other, on the utility you mentioned some changing in schedule of some of the spending and it needing some of that being subject to regulatory approval. And one of the things we noticed from the slide was that the SmartConnect spending seemed to have been to potentially accelerated from what you showed in your last slide, it seems to show up - - those bars seemed to show up a little bit earlier. Can you just comment on that? And then whether that's one of the things that needs approval and what else might need approval in terms of the slight reshaping of the plan.

Well, I'll give a initial comment and then kick it down to Al if he wants to add anything. I think the regulatory approval is really is going to transmission. The thing there, because we don't control that, there are a lot of regulatory bodies that are involved in that process. And we have just seen from experience here that has taken longer than what we've originally included in our forecast.

On SmartConnect, we have flexibility there. If we want to accelerate it, we can. The program needs to be done by a certain timeframe, so we can shift dollars sooner or later depending upon how things are going and how we pace the new installations. And I'll look over to Al to see if you want to add anything else?

Yes, that covers it.

Okay.

So is the plan that you're showing now an acceleration of Smartconnect?

This is Scott. It's a very slight change but as Jim pointed out there's flexibility within a couple of years; the key thing is the 2012 completion deadline.

Thank you very much.

Alright, John.

And our next question comes from Michael Lapides. Please state your company name.

Hi, I'm with Goldman Sachs. Good morning, guys. Got a question, how do you - - when you start thinking about the EPA, and for SOX, NOx and mercury, rules for - - really rules of the noticed and proposed rule-making process for really MAC standards. How do you juggle the decisions you are going to make on meeting your Illinois standards versus what could be somewhat of a different standard that may come down from the US government?

Jonathan, this is Ted. Or Michael, I'm sorry. I think there's a couple of pieces that are important to highlight here. You certainly have put your finger on one of the key ones, and as I've mentioned in my comments at the start, to have this degree of uncertainty is really difficult with capital intensive businesses. We have most likely an extended period of time where these things are going to be in flux. That tends to drive us towards trying to minimize the capital expenditure and even make some trade-offs in favour of higher operating expense over capital expenditures, because we know that these things are going to remain in flux. So that really has been behind the thinking of looking at some of the alternative approaches.

At this point one thing to keep in mind is the agreement that we made with Illinois back in 2006, really incorporated more stringent mercury, NOx and SO2 requirements than any - - really any of the other states or what the federal level had within care and [camera]. So I think our general belief is being able to meet what we committed to under the Illinois agreement would actually not likely be exceeded by any changes that would come down the pike on the federal level, or at least ones that we can foresee at this point.

Meaning that you're not concerned that you could wind up installs SNCR's to meet the NOx requirements but have the EPA require SCRs as a Mac standard or use something like trona for SOX and have the EPA say that that is not an acceptable Mac standard?

Well, again, that's really what I was referring to in the comments when I said that we want to make sure that whatever we come up with is durable from a regulatory standpoint and legally. So, at this point, I think you can assume we're not going to make investments in additional upgrades to meet NOx or SO2 unless we're convinced that they are durable from a regulatory and legal standpoint.

Got it, thank you.

Next question.

One -- one --

Go ahead.

One additional comment, Michael, NOx and SOX are currently subject to DACT rather than a Mac standard. And there is an economic portion to that, so I just wanted to point out that when it comes to the SNCR's and the dry scrubbers or trona injection, that that is a back standard rather than a Mac standard.

Operator.

And our next question is from Leslie Rich. Please state your company name.

Columbia Management. I have a question on your liquidity slide. You indicated that you, I think you said that you paid off some of the credit lines that you drew down at Mission in October.

Yes.

Not reflected in the September 30 numbers. So - - and that you are at normal levels now. Could you indicate what that is?

I haven't - - I don't have the numbers here. What - - we're just trying to infer that we'll have normal activity in terms of letters of credit to post for development activities and there could be some trading activities. And so it is going to vary and fluctuate month to month depending on what is happening within the Company. The important thing is that the portion that we drew down and we just put on the balance sheet as cash, and we had been investing, now has been paid back and we're back to regular operating activities.

Okay. So that $1.2 billion of cash that's sitting there as of September 30 is lower now?

It is.

Okay. But you can't quantify that?

No. We'll pick it up at the end of the year.

Okay. Thank you.

On our next question comes Lasan Johong. Please state your company name name.

Yes, RBC Capital Markets. Gentlemen, (inaudible) you go into a 33% standard, one has to wonder if there have been any studies done on significant unintended consequences on SCE grid. Pretty well that intimate and resource on that grid is going to be a pretty daunting task to manage. Has anybody at SCE done any preliminary studies on how much backup generation you are going to need and what grid technology you're going to have to add to the existing infrastructure?

We'll let Al Fohrer address that question.

Thanks. We've done a number of things working both with people inside the Company and outside and I think probably the best one to talk about is the California ISO has indicated that for the state to get to 20%, they have to have all the existing generation, meaning all the existing gas power generation still on-line and to go to 33% they are going to need even more. Exactly how much depends an awful lot on where the resources are located. A big issue in the 33% was the ability to use out-of-state renewable energy credits as opposed to having all of the generation inside California. So those types of questions have to be dealt with to ultimately decide exactly how much additional generation is required.

There would have to be substantial additional gas-fire generation primarily fast start peakers available in the state to integrate the amount of additional renewables. But, again, it depends on how much out of state they allow and where the facilities are located, how much of it is solar versus how many of it wind. And we're trying to work with the ISO and other parties now to make sure that those studies are done to better inform the policy-makers.

Is it a bad assumption for us to say that SCE is going to argue that those generation investments ought to be made on SCE's balance sheet?

No. The position we have pretty much consistently taken over the years is that generation is something that should look to the market. IPP's are available to do it. What we have indicated is we believe the utilities should always have the option to propose through the regulatory process generation when we thought it was in the customers' and the shareholders' best interests. The best example would be the Mountainview plant that we finished a number of years ago. Primarily we look to the independent power market to provide those resources.

Okay. Can I ask a follow-up question on that? Right now a rough guideline how much does California use of its own generation fleet - -in gas generation fleet, sorry? In --

(inaudible - multiple speakers)

How much does California - - you said that if -- in order to get to 20% levels you need all of California's gas-fired generation to be online and active, whether it is running or as a backup. But obviously that means that not all of it is being utilized today. So how much is that gap?

Well, all of the generation that we're talking about is in operation today. It is a matter of how many hours that it's operating. The ISOs study basically indicated that the additional renewable resources to get to 20% could not be accommodated if we lost existing gas fired generation capacity. So it's not a matter of is it sitting idle? It isn't. It is how much it is used and where it is located. Their point was that we need all of it if we're going to get to 20% and go beyond.

I see. So it's not a matter of megawatts, it's a matter of megawatt hours?

It's a matter of having the megawatts available to do load following. It's where they are located in order to provide voltage support. There's a lot of different pieces that go into how you reliably operate the grid.

Okay. Thank you very much.

And our next question comes from Steve Fleishman. Please state your company name.

Yes, Bank America, Merrill Lynch.

Hi, Steve.

Hi. Question on Midwest Gen. You mentioned that you've changed the operations a bit to make sure that you are optimally running the plants. Could you first give a sense of - -is there a way to get a good sense of what percent of the hours from the whole fleet are running, peak versus off-peak and how that has changed versus prior years? And also just from an operational standpoint, is this putting stress on the plant to be running in a different manner? And what does this mean for the long-term of the plants to be cycling more?

Well, let me take a little stab at it and then I am going to turn it back over to Ron for some additional details. What we've found during this year with the low prices, especially in the spring and the fall when you have slack demand, prices got very low. And what we needed to do was change the way we were operating to the extent that in the minimum loads that our plants operate, we had to carefully adjust those to make sure that we could then meet the peak that was required during the course of the day. And in some hours we were seeing that you were facing negative margins as a result of prices, where the prices had fallen to. And so there was an ongoing constant diligence to make sure the operations and the pricing reflect what you think is going to happen, and you don't face negative margins.

And the way we've really approached this problem, and tried to address it going forward, besides the operating characteristics we alluded to and Ron will give you a little more detail on, is hedge forward in the offpeak hours to avoid those negative margins. So you have more clarity in terms of how you are going to operate the plants and avoid some of the problems we've faced. So these are really more recent problems we've faced in 2009. So I'll stop there and look to Ron for further detail.

Yes, in 2009 we took actions in two primary places. First, your operating minimum for a coal unit is one level when you are operating just on coal. And you can lower it further by adding some supplemental gas fuel for support. And we would do that if the avoided negative margins by going to that lower minimum load were sufficient to pay for the gas. So that was one area that we looked at.

And there were some hours where the pricing was low enough and the margins were negative that if we were not taken in the first commitment at PJM, we would elect to go into a reserve shutdown as opposed to declaring ourselves must-run in the second commitment which we had done in the past when margins were slightly positive. But in a negative margin environment it does make more sense to shut the units down, avoid the negative margins, provided you'll be able to recover your start-up costs when you return, when the prices recover.

Steve, I know you're trying to somehow model this. I would say it's very challenging to do it because the market is so dynamic and the factors that are causing this, outages, congestion, the actual supply and demand, we find it challenging to really model it carefully too.

And just to reinforce what Jim said about the off-peak hedging we've done. We did that at a level such that we can operate the fleet at our operating minimums without going through the activities we had to this year.

Okay. One just related question, on the hedging, you said the 7.5 million megawatt hours were off-peak?

Yes.

And you added, are all the other the rest of the 20, is that all on peak hedges?

Primarily.

Okay. Thank you.

All right.

And our next question comes from Terran Miller, please state your company name.

Good morning, it is Terran Miller from Knight Libertas, how are you all today?

Good, Terran.

Just going through the EME CapEx, I want to make sure I understand two additional points. When I look at the remainder for 2009 and all of 2010, does the $206 million that you've done in terms of financing reduce those commitments - - or those requirements? Should we be netting that number against that?

The numbers you see -- this is Ron. The numbers you see in the table do have the $206 million in there. They are our capital expenditures. Think of it as you are looking at the investing portion of the cash flow statement and when we execute on the turbine financing arrangements, we would offset those with cash flows from the financing.

And we should think of those now against the projects under construction CapEx? Effectively?

The capital table reflects the projects under construction, that's correct.

Okay. And above and beyond that you have the ability to reduce those numbers by $181 million if you choose to cancel?

Well, that is an option - - one of the turbine supply agreements that we -- if we elected to go ahead and release our turbines. Yes, that's how you would get there. You would have to writeoff a portion of the deposit that you have already provided. And it would reduce it by the $181 million.

Okay. And can you split the $206 million as a credit against 2009 and 2010 for us?

It's - - it's not 2009. There's very little remaining for 2009 so (multiple speakers).

So, the $206 million we should think of against 2010.

Yes.

Thank you so very much.

Okay, Terran.

And our next question comes from Kit Konolige, please state your company name?

Soleil Securities, good morning.

Kit.

Just wanted to ask simply if you can give us any quantification of the weather impact on EMG for the quarter and the year-to-date.

Ron?

Yes, to use the statistical measures, I think the cooling degree days in the Chicago area were down 30% and I believe it's around 12% in the Philadelphia area. So between the weather and the low demand driven by the economic recession, you'll see in our statistics that our load factors were down fairly substantially.

Any way to translate just the weather into EPS?

No. There's - - you really can't do that without customer load.

I think that's a challenging estimate too, because we're a load following system.

Right.

And there are so many factors that play into that, that's a much more challenging analysis.

Ron, just a follow-up, on the cooling degree days, it was 30% lower in the Chicago market and 12.8% lower in Philadelphia. And that's about as close as we can get to tying it in. Because we're just not a load-serving entity.

And that - - so the 30% and the 12.8% are for the year, cooling degree days?

No, those are for the quarter.

Quarter. How about year-to-date?

I don't have that for year-to-date.

For year-to-date, you'd have to look at heating degree days in the wintertime and cooling. It would be quite a mix and tough calculation to do.

Right.

A tough calculation to do. And Jim has hit the primary point, our coal fleet is mid-merit and so there's just a multitude of factors that impact it in addition to weather.

Okay. Thank you.

Okay, Kit.

And our last question comes from Ivana Ergovic, please state your company name.

Hi, it's Jefferson Company. You have raised your guidance for the utility for the year. Is it because you are going to underspend for year or is there another reason beyond that?

Hi, Ivana. What I said in the script was there are a couple of factors that caused to raise guidance for the utility. The two principle factors were the FERC, the 2009 FERC rate case had a benefit from a higher rate base that we've already reflected in our rate base chart. And from the global tax settlement there's some interest savings and we've deferred some financings as a result for having the extra cash.

And so those are the principle forms of the reason why we raised the guidance and spending. We had been running behind in our spending. I think that's why you brought up the question. And we're forecasting that we will catch up to the levels of spending that are authorized in the general rate case. And I just want to make one other thing clear too. We are anticipating - - we do have in our guidance $0.03 for energy efficiency. And we're anticipating a proposed decision in the near future. They are running out of time quickly in terms of - -you have to have a proposed decision and then there is a 30-day period. And so we're running right up to the end of the year in terms of when we expect to see that.

Okay. So basically you are going to be in line with your spending by the year-end.

Yes.

Okay. Thanks.

This is Scott Cunningham. We want to finish up the call at this point. Thanks, everyone, for participating and don't hesitate to give us a call if you have any follow-up questions. Thanks and good day.

And thank you for participating in today's call. Please disconnect your lines at this time.