Ronald Litzinger - President of Southern California Edison Company Theodore Craver - Chairman, Chief Executive Officer and President Linda Sullivan - Pedro Pizarro - President of Edison Mission Group Inc and President of Edison Mission Energy W. Scilacci - Chief Financial Officer, Executive Vice President and Treasurer Scott Cunningham - Interim Head of Corporate Communications and Vice President of Investor Relations

Michael Lapides - Goldman Sachs Group Inc. Terran Miller - UBS Paul Patterson - Glenrock Associates Jonathan Arnold - Deutsche Bank AG Ashar Khan - SAC Capital Brian Taddeo - Broadpoint Capital Justin McCann - S&P Equity Research James Dobson - Wunderlich Securities Inc.

Leslie Rich - Columbia Management Ali Agha - SunTrust Robinson Humphrey, Inc. Unknown Analyst - Raymond Leung - Goldman Sachs Group Inc.

Ivana Ergovic - Jefferies & Co Brian Chin - Citigroup Inc Steven Fleishman - BofA Merrill Lynch Hugh Wynne - Sanford C. Bernstein & Co., Inc.

Thank you, and good morning, everyone. Our principal speakers today will be Chairman and CEO, Ted Craver; and Chief Financial Officer, Jim Scilacci.

Also with us are other members of the management team. The presentation that accompanies Jim's financial review, together with the earnings press release and our 10-Q filings, are available on our website at www.edisoninvestor.com.

This afternoon, we'll be posting on our website our quarterly business update presentation and we use these slides in the regular order for our ongoing investor discussions. 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 SEC filings.

We encourage you to read these carefully. The presentation includes certain outlook assumptions, as well as reconciliation of non-GAAP measures to the nearest GAAP measure.

[Operator Instructions] With that, I'll turn the call over to Ted Craver.

Thank you, Scott, and good morning, everyone. Our first quarter results are fully consistent with our 2011 outlook.

Core earnings were $0.62 per share compared to $0.82 per share last year due to the expected loss of Edison Mission Group. Southern California Edison delivered a 10% increase in earnings to $0.68 per share, reflecting continued growth in rate base as SCE implements its multibillion dollar capital program.

We are also reaffirming our core earnings guidance for 2011 of $2.60 to $2.90 per share, with a midpoint of $2.75 per share. Jim will provide some additional detail on our financial results in his remarks.

I would like to review a few key developments that have occurred thus far this year, starting with SCE's 2012 to 2014 General Rate Case. In early March, the CPUC approved the timeline for the rate case, which still calls for a commission decision by year-end.

As with our last rate case, should the case carry over into the next year, we have received CPUC approval to make any rate case decision retroactive to January 1, 2012. We will shortly be moving into a phase in the case involving intervenor testimony and responses along with public hearings.

Last week, SCE made an important procedural filing to reduce its revenue request, primarily to reflect last year's tax law change on bonus depreciation. Tragic events in Japan have increased the public's focus on nuclear power generation, including at our San Onofre Nuclear Generating Station.

SONGS continues to operate normally and safely. We are assessing events in Japan and beginning a thorough process of evaluating the causes of the nuclear part of the disaster.

We, and the entire U.S. nuclear industry, are working to glean every insight we can from the Japanese experience and then make any necessary improvements to equipment, procedures and emergency preparedness planning.

The SONGS' design basis, including seismic and tsunami events, is conservative and of course meets all NRC requirements. San Onofre's reactor cores are housed in 4 to 8-foot thick reinforced concrete and steel-lined containment structures.

Similarly, the spent fuel storage pools are housed in seismically-designed concrete structures. In an emergency, regardless of the cause, it's critical that the plant can shut down safely, contain any radiological release and keep the nuclear fuel cool.

To accomplish this, the plant has multiple redundant backup systems that can operate even in the event of a loss of electric power for an extended period of time. Additionally, multiple emergency measures have been introduced over the years especially after 9/11.

Seismic analyses, updated in 1995 and again in 2009, have reconfirmed the design basis of the plant. This research also determined that the maximum credible tsunami at San Onofre is 23 feet.

Our tsunami wall is 30-feet high. However, not wanting to leave any stone unturned, on April 15, SCE filed a previously planned request with the CPUC to authorize funding for additional seismic research using the latest 2-dimensional and 3-dimensional technologies.

This work will also provide support to any future capital required at SONGS for its continued safe operation and any request we may seek in the future for license renewal beyond 2022. We continue to recover through rates all of our investment in SONGS such as the previously completed steam generator replacements, based on the current expiration of the license in 2022.

While on the subject of license renewal, it's worth noting that on April 21, the NRC approved the license renewal for the Palo Verde Nuclear Station, where we have a 16% or 621-megawatt ownership interest. I'd also like to comment on California's recently enacted legislation targeting 33% renewable energy by 2020.

We believe this should be an achievable goal, but one that will be challenging and comparatively expensive. Meeting this goal requires policies that support the integration of these new technologies into the electric grid, recognizing the realities of intermittency of renewables, resource location and the need for increasing transmission in a timely manner.

Transmission remains SCE's key investment priority in meeting the 33% renewables requirement, because the vast majority of untapped renewable resources are in its service territory and transmission remains a bottleneck to delivering 33% renewables power. Planning for implementation will be complicated by California's once-through cooling water policy, which is more stringent than the recently proposed U.S.

EPA rules. By 2020, California's rules may affect up to 7,000 megawatts of IPP-owned gas-fired generation important, for managing renewables intermittency in SCE's territory.

Maintaining grid reliability will probably require repowering some of these sites or citing new generation. Turning to Edison Mission Group.

We continue to work hard to unlock the equity value we see in this business. Our priorities remain enhancing liquidity and financial flexibility, addressing the challenges of the coal fleet and diversifying the portfolio through our renewables development platform.

Although EMG reported a $0.05 loss in the quarter, it continues to generate positive cash flow and EBITDA. Adjusted EBITDA was $106 million in the first quarter.

EMG continues to make decisions that maintain a solid liquidity position, as it increased cash and investments over the quarter to almost $1.2 billion. We continue to fine-tune EMG's capital spending program, including optimizing capital spending for emissions controls at Midwest Generation to meet all commitments to the Illinois EPA in the time frames agreed.

Our wind construction program actually netted positive cash proceeds in the quarter as projects utilized the U.S. Treasury Grant Program.

A major event in the quarter was the release of U.S. EPA's draft Hazardous Air Pollutant Rule or the so-called HAPs MACT rule.

The section covering mercury emissions proposed the same emission limits as contained in our 2006 Illinois Combined Pollutant Standards agreement for Midwest Generation, 0.008 pounds per gigawatt hour. We installed the necessary equipment back in 2009 and are already achieving these limits.

U.S. EPA's rule contained other draft provisions covering acid gases and non-mercury metals, which we can meet by installing the pollution control equipment we have been planning to use at Midwest Gen to meet our SO2 emissions commitments to the Illinois EPA.

Finally, EMG continues to make good progress building out its renewables platform. In April, EMG commenced construction of a 55-megawatt wind generation project in West Virginia called the Pinnacle project.

This marks EMG's 30th project and now has nearly 2,000 megawatts of wind generation in operation or construction in 11 states. EMG intends to remain active in developing new projects as we look to partner with one or more financial institutions to fund additional good-quality projects while leveraging our 3,700-megawatt pipeline and strong development team.

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

Thanks, Ted, and good morning, everyone. Page 2 of the presentation summarizes first quarter GAAP and core earnings.

Ted has already summarized the core results. Both periods had minor non-core impacts from EMG's discontinued operation, and last year's first quarter included a $0.12 per share charge at SCE related to healthcare reform.

Page 3 reflects SCE's first quarter financial performance, which is consistent with our guidance that rate base growth will drive higher earnings at the utility. The $0.06 per share increase came largely from higher authorized CPUC and FERC revenues.

The CPUC revenue increase is the attrition mechanism which increases 2011 authorized revenues by 4.35% and other approved investments such as the Edison SmartConnect and SONGS steam generator replacement. The FERC revenue increase is mainly due to the implementation of the 2010 General Rate Case decision and construction work in process or CWIP return on transmission investment.

I'd also like to touch briefly on SCE's 2012 General Rate Case. Last week, SCE updated its GRC application to incorporate specific changes, including the impact of the 100% bonus depreciation for years 2012, '13 and '14.

In investor materials we provided for our fourth quarter 2010 earnings call, we included the estimated impact of SCE's rate base of 100% bonus depreciation. Based on recently issued IRS guidelines for 100% bonus, we are now confirming that our previous rate base forecast is consistent with these regulations.

As part of SCE's updated filing, the utility also removed the seismic study costs for SONGS to a separate proceeding. Together, these changes lowered SCE's requested increase by $38 million in 2012, $133 million in 2013 and $145 million in 2014.

Page 28 of the investor deck has all the updated GRC information. Turning to Page 4.

First quarter EMG results were consistent with our full-year outlook. Core earnings declined $0.27 per share.

There were 4 major factors at play here: First as expected, EMG experienced lower realized energy prices, largely due to expiration of hedged contracts at Midwest Gen and Homer City. Emerging coal fleet also had lower generation due to the outage at Homer City Units 1 and 2 as we discussed on our year-end call, and the shutdown at Will County Units 1 and 2 pursuant to EMG's agreement with Illinois EPA.

EMG also received project distributions during the first quarter of last year from Doga -- March Point that did not recur this quarter. Lastly, trading income was lower.

We did see improvement from renewable portfolio increasing $0.03 per share overall. EMG's coal fleet operating performance, excluding Homer City outage, was generally comparable year-over-year.

We've included our normal summary of operating statistics and average realized prices on Pages 40 and 41 in the presentation. Regarding Homer City, repairs to Unit 1 were completed and unit returned to service on April 5.

We expect Unit 2 to return to service later this quarter. Although generation from Homer City was down a terawatt hour, the results were consistent with our 2011 earnings guidance assumptions.

Turning to Page 5. EMG added modestly to its coal fleet hedged position.

We continue to believe that we can add value to the enterprise by being less hedged compared to our normal strategy of hedging 50% of the gross margin at risk for the comp year and lesser percentages in the out years. Midwest Generation added 2 terawatt hours of hedges in 2012, and 1 terawatt hour in 2013.

At Homer City, we made very minor changes in coal and energy positions compared to last quarter. Page 6 shows the continued progress of EMG's renewable energy portfolio, which Ted has already commented on.

One area that EMG continues to work on is wind financing opportunities. Most recently, EMG refinanced its Viento project financing and increased the overall financing by $85 million and netted $77 million of incremental cash after transaction costs.

EMG is continuing to look for opportunities to project finance the 920 megawatts of unlevered projects and for third-party capital to continue development of new projects. As the chart on Page 7 shows, wind sources of cash exceed uses primarily from the expected receipt of Treasury cash grants from projects completed during the first quarter of 2011.

Overall, wind capital expenditures are coming in at or below planned costs. Page 8 shows EMG's updated capital spending forecast.

The primary change from year-end numbers is that we lowered our NOx compliance capital costs by $25 million. For SO2 compliance, we have not changed our overall estimate of up to $1.2 billion in capital costs if the entire Midwest Gen fleet were to be retrofitted.

We did, however, shift some 2011 expenditures into '12 and '13 while some expenditures for particulate upgrades were shifted forward into 2013 from later periods. Once the final HAPs MACT rule is released, we will update our compliance capital costs estimate.

Meanwhile, EMG continues to look for opportunities to optimize schedule and reduce capital costs. Although EMG's capital forecast does not reflect it, EMG is continuing to develop work on a 479 million -- 479-megawatt natural gas-fired project.

Let's refer to it as Walnut Creek. We estimate the project's cost between $500 million and $600 million, and it has a 10-year contract with Southern California Edison.

There are a number of critical development milestones still needed to be accomplished, the project could plausibly commence construction before July 1 of this year. EMG is also actively pursuing a project financing for Walnut Creek.

This project has been stalled for some time pending a resolution of the priority reserve issue, which relates to the requirement of project's own emission credits as a condition of obtaining a construction permit from local air quality authorities. EMG continues to exclude from its capital forecasts any environmental retrofit capital spending for Homer City to meet the expected Clean Air Transport Rule requirements.

EMG is discussing with the principal owner the appropriate environmental equipment and how such equipment will be financed. Page 9 provides key financial covenant ratios for EME, Midwest Generation and Homer City.

The unplanned outages of Homer City Units 1 and 2 and the continuation of lower power prices have impacted Homer City's liquidity. In order to have sufficient working capital available for operating expenses and to pay the equity portion of Homer City's rent payment that was due on April 1 to the owner lessors, Homer City took a number of actions including drawing $12 million from an equity reserve account, accelerating payments on EMMT for future energy deliveries and adjusting payments of operating expenses.

These actions were discussed in more detail in our 10-Q. To further enhance Homer City's liquidity, effective April 1, EMMT assigned to Homer City a benefit of an arrangement that allows EMMT to deliver power to the New York ISO from Homer City.

These revenues were recorded as part of the Homer City revenues in lieu of prior classification as EMMT trading revenues. EMMT trading revenues of $28 million -- excuse me, EMMT realized trading revenues of $28 million under this arrangement in 2010.

I'll finish up with a few comments on 2011 earnings guidance. Please turn to Page 10.

As Ted mentioned, we have reaffirmed our 2011 core earnings guidance of $2.60 to $2.90 per share. We have updated our GAAP guidance to reflect $0.01 of EMG first quarter non-core items.

This guidance reflects our principal operating assumptions, including updated EMG forward hedged positions and prices as of March 31. We also reaffirmed EMG's adjusted EBITDA guidance of $465 million.

We have lowered our guidance for EMMT trading revenues by $25 million this year. This reflects the assignment of revenues I just discussed.

This does not impact expected EMG results as the offset will be recorded in additional Homer City revenues. That concludes my comments, and I'll now turn the call over to the operator for Q&A.

Just a few quick ones. With the cooling water issue that you guys mentioned on Page 33 of the 10-Q, could you just give a little more feeling for what the Midwest Gen exposure might be?

What I'll do, I'll turn that over to Pedro Pizarro.

Our initial analysis indicates that the proposed rules themselves should not have a material impact on the Midwest Gen coal fleet. And by the way, Homer City already has cooling towers.

EPA have stated that it expects what are called modified traveling screens to meet impingement rules for holding and releasing fish that are impinged by intake structures. So we're updating our cost estimates for these modifications, but they are not material.

We also have something called entrainment standards and those could require cooling towers. But with those, the agency has proposed some site-specific flexibility and factors to consider that we think indicate that units like ours should not be required to install cooling towers, and the factors we're considering include things such as particulate emissions from cooling towers, availability of land to build towers, cost-benefit, impact on overall water body and projected useful life of a plant.

So however, Illinois is evaluating some more stringent water quality rules related to thermal discharge limit that could impact some operations.

Okay. And then on another topic, the Wind portfolio.

Another company has increased its life expectancy associated with what it sees for its wind turbines. And I was wondering if you could tell us, a, what the expected life for the newer turbines that you've been procuring is, and whether or not you see any potential change in the life expectancy of wind turbines?

I'll have Maria Rigatti, the CFO of Edison Mission, answer that.

We don't expect to increase the depreciable life of our unit at this time. We use a 20-year depreciable life and thus far, we think that, that's the appropriate time frame.

Just a quick question on your SCE rate base forecast. The forecast that you presented in the fourth quarter and I guess repeated in the first quarter incorporates the extension of the bonus depreciation.

It's somewhat higher, the range you've provide is somewhat higher than the old forecast that you presented in the third quarter. I just wondered why that was.

It really goes back to what we said in the year-end call. There were a number of things that occurred as part of the update process.

There were dollars that were shifted. We actually dropped out some expenditures associated with the Solar Rooftop Program, and there were some timing-related issues shifted from one year to the next.

And I'll stop and ask Linda Sullivan if there's any more there that we should comment on.

Yes, Hugh, what we did was we trued it up to our General Rate Case filing. We adjusted it downward for the Solar Rooftop filing, as well as the bonus depreciation.

So what drove it up?

The true-up to the CPUC General Rate Case filing, as well as moving the timing of some issues around.

What do you mean by true up?

We ended up putting into our rate case filing -- our ratio to rate base is what we've included in our rate base filing so that's the full request.

So basically, you've added some projects. You've shifted some projects in time.

And you brought up the bonus depreciation.

Right.

A quick one on Homer City. I mean, you said that you're still trying to figure out how to finance the necessary SO2 scrubber installation I guess at Units 1 and 2.

Pretty much running out of time to get those scrubbers online by 2014 when the Clean Air Transport Rule will come into effect. What are the implications for the availability of that plant in the 2014, 2015 capacity market?

Well, we will actively participate in the auction. As you know, it's coming up soon.

And related to that question is that there's ongoing and active discussion with the owner lessors on what equipment we're going to utilize and how we're going to finance that. We understand the time frame is relatively short.

So we're thinking hard about that and doing preliminary engineering work as you would expect, so we can move along as quickly as we can.

So the strategy, in other words, for you to have the plants scrubbed by the time the summer of '14 rolls around?

Yes, exactly.

Could you give us a sense of what reaction or feedback you've gotten from the regulators now that the 32% renewable mandate has been approved? Any implication at how they're looking at the utilities and general cost of capital, the risk profile?

Any sense of how they're viewing that, especially as cost of capital discussions start to come up next year for you and others?

Ali this is Jim Scilacci. I'll start and hand it over to Ron Litzinger.

As you probably know, our cost of capital is going to be in place through the end of next year. And we have the triggering mechanism in place now and we don't anticipate that it would result in any changes.

Clearly, that was something that we'll be focused on as we go into the first part of next year. The procedural schedule would be that we would file for whatever we're going to do in May of next year.

And then we'd probably litigate it through the balance of the year with a decision probably in December before it would be reset. So we haven't come in to any conclusion yet on what mechanism we would likely propose.

But as you would expect and it's obvious with lower interest rates, there may be some pressure on the return on common equity. But the real important time frame will be in the fourth quarter of next year, when they really get down to thinking about what the appropriate rate of return would be.

Ron, would you add anything?

Our discussions at the PUC with the commission, we've been discussing at a very high level. And this is while the legislation was still in place, the potential upward pressure on rates and recognizing the impact that has with our need for reliability investments as well and generally, at that high of a level in our discussions.

Okay. Jim, if I heard you correctly, are you saying the low interest rate environment likely puts downward pressure on ROE; when you balance that against the need for more renewables, et cetera, are you budgeting assuming a lower ROE on a going forward basis?

Did I hear that correctly?

Yes, I didn't say that. What I said was that it was the current lower interest rate environment that potentially could some put some downward pressure on return expectations if you were to get a decision now.

But the critical time frame, which I'm saying is going to be next year and especially in the fourth quarter of next year, when the commissioners will be deliberating on the appropriate return on common equity.

Understood. One question, quick one.

As you look at your CapEx numbers as they start to get firmed up for the next 3 years, would you just remind us again where you stand with regards to potential need for additional equity for EIX?

Yes, and a critical piece of that is what's going to happen in 2012 GRC because that will set the expectation of capital spending and the timing of the transmission expenditures, which obviously flows through a lot of procedural steps and ultimately ending up at FERC. And we have no plans for equity.

And as you know, the bonus depreciation this year and next has the ability to enhance our cash flow such that we just don't have any plans currently for equity.

Ted, your commentary at the beginning of the call on the RPS standard, and I'm going to mess up the quote here, but it almost made it sound like you view it as a challenging standard and an expensive standard for the state to meet. In most states we've seen -- or in many states, we've seen a movement to where the utility, meaning in rate base, is taking a little bit larger of a role in adding renewables.

It seems you're going the other direction. I want to make sure we understand why and whether you think the RPS is achievable if SoCal Ed [Southern California Edison] is actually not a big builder of renewables and rate base?

Yes, the quote was challenging and comparatively expensive, and I think that is how we view the 33% renewables. There aren't other states that have gotten to this aspirational level.

I think the other element is a lot of things have to come together and work together in order to achieve the 33%. I highlighted one of those policy responses, which was the once-through cooling.

If we end up taking out a number of megawatts of gas fired generation, it makes the integration of a much higher renewables level all the more difficult. And that's the part that we really need to make sure that policymakers and the public fully understand is, this is an integrated engineered system.

It's not simply a one-dimensional system, and we need to be able to ensure the reliability of the grid. And that's going to be a fairly complex undertaking.

That's the challenging part. If you were taking out fossil-fired generation and replacing it with renewables generation, at least the current technologies, then that is more expensive.

So that's the comparatively expensive part. The final point I guess I would make here is we see the transmission as being one of the key bottlenecks at this point to actually delivering the higher level of renewables to where the load is.

And since we believe we are uniquely positioned to design and build transmission and very importantly, get it permitted so that you can build it, that's really where our focus point is. So there are plenty of people that can do the renewables development, the actual generation projects and we feel that's a pretty robust competitive market.

That's how we really get the best prices for our customers, is to have good solid competition and there are plenty of people who are interested in doing that. It's the transmission that's the more cumbersome and difficult bottleneck, and that's where we're uniquely positioned to add value.

Got it. Jim, one question.

I missed something, the reason for leaving Walnut Creek out of the CapEx forecast?

It's a good question. That's why we highlighted it.

There are a number of critical development milestones that we need to get through, and we're just not sure if we're going to be able to do all those things. So we're flagging it as a potential.

And if we're going to do something, it would be before July 1 because the rules, the environmental rules change after July 1. So we're flagging it and we'll let you know as we go down the path here, what happens.

What does SCE do if Walnut Creek doesn't get built?

That's a tough question. They go through an annual review or they have a long-term procurement process they go through that they're in the process of right now.

And so they'll determine what their total need would be. And it would come out of that process, if there's additional requirement for new generation, Michael.

A couple questions. First, when you guys are talking to public policymakers about 33% standard, what kind of communication do you give them about how much rates could potentially go up to meet that?

This is Ted. It was part of the overall discussion in the legislative sessions.

This has been going on for 3 years or so. And so I think it's understood that at least amongst the policymakers, it's understood that there's going to be additional costs associated with this conversion.

The PUC, a couple of years back, commissioned a study that suggested to get to 33% was going to cost, if I remember the number right, around $112 billion, which included both transmission and generation. So I think it's understood that it's a comparatively, I'll use the same phrase, comparatively expensive proposition to get there.

Beyond that, I don't think anyone has tried to specifically cover all of the elements, in part because we're talking about something that's going to take us out to 2020. So that hasn't really been baked into the rate cases that ultimately will be required to get us there.

But I think they generally know it's going to be comparatively expensive.

Okay. One other question, kind of switching topics on Edison Mission.

Ted, you've said a number of times that you see the potential for equity value. And I'm just wondering over the last few months, I mean, particularly the financing market has gotten, continued to get better, tax equity financing, partnerships.

We saw Energy Future get an extension of their maturities. Kind of what's your level of conviction today versus, let's say, 3, 6, 9 months ago on the potential to kind of get through the tough times?

I'll just give a couple of general comments. I think we looked at this very hard over many, many months and looked, as you know, at all of the alternatives that we had for Edison Mission Group.

After that review, we concluded that the best course of action for shareholder value was to continue to hold EMG and work the issues as aggressively as we can. In this business, of course, so much rises and falls on what happens with commodity prices.

We believe it's still a cyclical commodity market and that we will experience some level of recovery but of course, nobody can guarantee that element. But there are a host of other issues that we can work and that we are continuing to work.

And so far, I would say, those issues have been moving in the right direction from our perspective. And we've gotten a little improvement on commodity prices both on the coal and the power side, which helped things at this point.

But again, it's cyclical and those things go up and down. So net-net, I'd say we feel every bit as much conviction to continuing to work the issues as aggressively as we can, focus on those things that we can control and try to manage this as effectively and as deftly as we can.

Just one question I have was that, are you still anticipating proceeds from insurance to cover some of the Homer City outage costs? And I think you've mentioned on the last quarter, we didn't see anything in the Q, and wondered if the timing is -- how that will sit with where you need to keep that credit metric and just maybe some context on that.

Yes, on that, I don't think that -- we are certainly focused on getting insurance recoveries. We will have to discuss that with the insurers in terms of what qualifies and what doesn't.

But I don't think the dollar amount here is going to be sufficient enough to really change the metrics all that much. Commodity prices, as you know, Jonathan, swamp all this.

So that's the key.

Okay. So it wouldn't be a big recovery in any event?

It is not a big number.

Okay. And then could I also ask on the coal transportation contract expiry in, I guess, for Midwest Gen, does having the HAPs rule out and your comments around you're anticipating you'd be able to comply with it, is that enough of a catalyst to sort of get to a point where we could see some movement?

Clarification there or is that more likely later in the year?

Yes, I think it's more likely later in the year and we'll report it when we get through it.

And if I could just ask one on the utility. I mean obviously, they've had some changes at the commission.

And can you comment on whether you're having, with new commissioners in place, it sort of makes it any more or less likely you might be able to settle at least some of the issues in the case? And I know in the last case, there was a push to move in that direction, didn't really come about.

But how should we think around the possibilities there?

I'll have Ron Litzinger address that.

Yes, the commission is entirely in place now. We have reached out and had initial conversations with all of the new commissioners, including face-to-face meetings.

And we will continue to work with the commission on all of the tough issues we face like we always have.

Just a quick clarification on the EMMT trading margin. What was your previous expectation for the 2011 trading margin out of EMMT?

What we did, in the guidance chart, you can see we shifted $25 million out of each side of the range implying that it's gone over to the Homer City side and will appear through the books there.

So it used to be $75 million to $125 million and now it's $50 million to $100 million?

Correct, Leslie.

Okay. And also, I'm no bond analyst but on Page 9, it shows the debt covenant status for Homer City getting sort of close there.

Is that a function of the outages that were going on? Or do you foresee that there's some sort of covenant breach situation?

Yes, this was a tough issue during the quarter with the outages at Units 1 and 2 and with the lower prices. It put some real stress on this metric.

And in my prepared remarks, there was a number of things that we did in order to achieve the metric. So we'll continue to watch that very carefully.

We have annual rent payments that occur there. The next one is April 1 of 2012.

And what helps this metric the most is recovery of power prices in continued operation of the plants.

Okay. So that's perhaps part of the reason why you shifted around the EMMT revenues?

Exactly, it was.

I noticed on Slide 8 for Midwest Gen, you've got a little bit of changes on environmental expenditures. You say that the HAPs MACT did not affect the overall estimates.

But the timing of Midwest Gen expenditures to meet compliance deadlines just shifted around. So we see that some of the spending in '11 has been pushed out a little bit, some of the spending after '13 apparently has been pulled up.

Can you just give a little bit more color on what's going on there? And what changed versus your expectations?

The one thing we've mentioned specifically was the NOx expenditures dropped by $25 million. The project came in under what we anticipated, so we removed that from the capital forecast.

And we shifted some expenditures. Now, part of the strategy we've been working on is trying to optimize expenditures of coal and time frame.

And all these things, we continue to move these things around to make sure that we can comply with the rate requirements, but minimize costs to the extent possible. And I did mention, too, that we shifted, forward some particulate expenditures that were outside of 2013 into 2013 as we're looking at the rate levels and what was included in HAPs MACT, it required some additional expenditures in '13.

So this is all live radio. We're continuing to evaluate this.

And I think what's going to happen, it's going to be at the end of the year when you get a final rule, we'll re-evaluate the total figure again to see if it's appropriate given whatever ultimately is decided.

Jim, I wanted to go back to the rail contract. Could you just give us an idea on sort of where those negotiations stand, and then maybe remind us what sort of competitive dynamic you have to exert between UP and Burlington Northern in the negotiations?

That's a tough one to get into here on the phone or even in private. Just assume that we're in discussions and we're trying to create as much leverage as we can.

And then we'll announce an ultimate contract later on in the year. Sorry, can't be more helpful.

Got you. But I assume one option is to just simply go to an uncontracted status and just pay some market tests, sort of how things go there.

Not that I know that's probably the one you'd like, but that's an option.

Yes, it would be a challenging one. So we'll just have to see how it works its way through.

Okay, perfect. And then just separately but in the same region, I was hoping you could give us a little idea of what you or maybe Pedro is seeing in sort of Midwest power prices?

I appreciate your comments. I mean, they haven't changed and you've wanted to be more open as you look out into the '12 and '13 time frame for Midwest that haven't really changed very much to see the hedging status.

But just sort of what you're seeing and then with HAPs MACT already out there, have you gotten sort of more confident in your fundamental view? And what's out there to support it?

Yes, there's not a lot to add here from a sense that we opened up our hedged position. That has worked well to date, which is good.

And we'll just see where the dynamics will go. We've been anticipating all along that power prices would recover, and it's always hard to predict the actual time frame.

And that's why we took the position we did to open our hedged position. And I look over at Pedro to see, do you have anything else to add?

I guess the only thing I would add, Jim, is that energy price, since we also watch what happens in the capacity market, and we'll get more insight as we get through the upcoming 2014, '15 capacity option.

Got you. Now that's fair.

But Pedro, I mean, what you're seeing in forwards is sort of consistent. I mean, they haven't moved around as much, certainly it's not as much as you've seen in other markets around the country as far as the recovery goes.

And that's sort of consistent with your view of being more open?

Yes, I think we're all looking at the same forwards. We continue, as Jim said, to look favorably on staying open.

As Ted mentioned, we're seeing a little bit of recovery since the end of year. But...

I was wondering if you could maybe tell us what is your experience, whether you can sort of be able to use Trona [indiscernible] instead of scrubbers for compliance in Homer City.

Yes, I think we've -- Ivana, this is Jim Scilacci. And we've done some testing of Trona at Homer City.

And frankly what we've found, that it was not nearly as effective as we're seeing in Midwest Gen and probably the sulfur content has a lot to do with that. And so there are some limited applications with Trona and potentially at Homer City, but I think what we're going to do is ultimately the technology we're looking at for the 2 units at Homer would be to scrub those units.

Okay. And are you going to include the [indiscernible] costs in your PJM, RPM auction bids, upcoming bids?

Okay, what I'll do here is just I think for right now, what we'd like to say that we don't want to get into the public domain, what our actual process is going to be around the bid. It's obviously sensitive and we'll just defer that.

Okay. And just another quick question.

Are your hedges mostly on peak or is it off peak? I don't know if you can comment on that.

All I'll say is we've added slightly to our hedged position in 2012, you can see the Midwest Gen. What we would like to do when there are opportunities to hedge in the off-peak hours, it's really to make sure in those shoulder months that we're not avoiding or avoiding operating at a negative margin.

So that's what when we'll pop in some off-peak hedges. And we traditionally have hedged more on the on-peak hours just because that's where our gross margin is located.

So make grades and make some both, right? And your hedges are more off peak?

It is. It's weighted towards the on-peak with selective hedging off-peak in the shoulder months.

A couple of -- First, on Homer City. I was wondering if you could comment with the switching or changing the contracts from EMMT to Homer City, do you think that will keep you in compliance with the ratio throughout the rest of the year?

Yes, it's hard to answer that question. Really, what keeps us in compliance fully is the power prices.

And so -- and capacity prices for that matter. And so it's one of the tools in our bag of tricks that we could utilize.

But ultimately, we're going to need power prices to recover to more appropriate levels.

If you hadn't switched the contract over in the quarter, would you have not been in compliance?

I don't want to get into talking about what could or should have happened. I'd just say that we did a number of things.

It's fully spelled out in our disclosures, and we'll just have to see where it goes going forward.

Got you. Also, in Homer City, it looks like you actually pulled some -- sorry, you also mentioned where you pulled some of the payments forward, from EMMT.

Now, how much capacity do you have to do that? And is there still quite a bit of cash you can actually pull forward from them?

Yes, again, I'm going to stick to our disclosures in terms of what we've said there and not get into discussion about capacity or what other options we might have. So I'm limited to what I can say, Brian.

Okay. Then in one -- other one on tax bonus depreciation.

Do you have an updated view as -- will EME have to make any payments to SCE tax bonus depreciation over the next couple of years?

No, we haven't said publicly what the impact is in all years from bonus depreciation. What we've said was that we'll likely be in a NOL position on a federal basis in 2011.

And it depends on what happens in 2012 if we will be there. It's a possibility.

So I really can't answer your question at this point in time what might happen with EME.

My questions have been answered.

Just a quick question, Jim, in terms of the insurance that you hoped for, I’m talking about previously at Homer City, do you think that would be sufficient to refinance or refund the equity reserve fund? Is it in that order of magnitude or do you think that has to be funded from other cash flows?

Yes, I don't want to get into the exact numbers here, Terran. We've said that the insurance is what I would consider not to be material.

Just a few follow-ups. At Homer City, just on Unit 2, bringing that back online is -- I guess is this longer than you expected?

Is there anything causing that or any additional work you're doing there?

What we're doing at Homer City, we're continuing to work on the piping situation there that was troublesome for both units. And I don't have a fixed date in terms of when we expect that will come back.

And we'll just -- when we finish all the work, we'll ultimately get it back online and unfortunately, I just can't give you a date.

Okay. And then was it a contract that was assigned from EMMT to Homer City?

And if so, was it a Terra battery [ph] and was that affecting capacity payments available to Homer City?

It does not affect capacity payments in any way. It's just the transfer right that Homer City utilizes to send power to either PJM or the New York ISO.

Okay. And just the Midwest Gen, the accelerated CapEx in there, was that largely due to need to add backhouses across [indiscernible] sooner than expected or were there certain plants that were added into the mix?

You're really speaking out on the question. I think you're asking about Midwest Gen.

Sorry, yes. Just the additional spend there that kind of accelerated, was that specific to additional plants being included in the estimate?

Or was that in regard, you mentioned in particulate, does that have to do with backhouses being included now in a sooner date?

It really had to do with particulate removal. So we haven't been specific what technology is shifting.

So we're just vaguely saying that it's particulate removal.

Okay. Just lastly on Walnut Creek.

If that does move forward, is $150 million the right ballpark for the equity contribution?

I think just a rule of thumb, we'll probably look for a project financing of about 75% of the project, and then the balance then would be equity.

Just to follow on that last question first. Just on the timing of equity, would that be front-end loaded or back-end loaded?

And then if you could talk about sort of your bank facilities and where do you stand with that, any particular update there. And what you're thinking about the 2013 maturity.

The equity would probably be front-end loaded. Normally, it would go in first and would draw on your project financing.

The bank line and the 13s are tied together. And I don't really have anything to provide you an additional update.

We're working and focused on those. We understand next year they're coming due.

And so we need to resolve the 2 issues together. And we don't have an answer at this point in time.

Thanks very much, everyone, for participating today. And please don't hesitate to call us if you have any follow-up questions.

Thank you.