愛迪生國際 (EIX) 2011 Q2 法說會逐字稿

Good morning. My name is Candy and I will be your conference operator today. At this time, I would like to welcome everyone to the Edison International second-quarter 2011 financial teleconference. (Operator Instructions). Today's conference is being recorded.

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, Candy, 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 of the Company, Jim's financial review, together with the earnings press release and our 10-Q filings, are available on our website at EdisonInvestor.com. This afternoon, we will be posting on the website our regular quarterly business update presentation that we use for our ongoing investor discussions.

During the 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.

When we get to Q&A, please limit yourself to one question and one follow-up. If you have further questions, please return to the queue.

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

Thanks, Scott, and good morning, everyone.

Today, Edison International reported second-quarter GAAP earnings of $0.54 per share, compared with $1.05 per share last year.

Core earnings in the second quarter were also $0.54 per share and compared with $0.62 per share last year. Core earnings in the first six months were $1.16 per share and compared to $1.44 per share for the same period last year.

Second-quarter and year-to-date earnings performance is fully consistent with our 2000 earnings guidance (sic - see Press Release). In fact, we now expect full-year earnings to be at the high end of our earnings guidance range.

SCE continues to deliver solid earnings growth as it implements its capital investment program, although second-quarter comparisons were impacted by favorable tax items that occurred last year. EMG recorded a loss for the quarter, which was expected, but we are encouraged by the recent improvement in capacity and energy prices. As always, the third quarter will be a key determinant of full-year performance, and we expect to update our full-year earnings guidance when we report third-quarter results.

I'd like to spend most of my time this morning focusing on our key strategies and some important developments. I'll start with SCE and its general rate case.

We are well into the rate case process now, having completed several public participation hearings across the state, responded to intervenors with rebuttal testimony, and commenced evidentiary hearings which will continue through the end of this month. The formal schedule contemplates a decision by year-end.

At a high level, the issues raised by the intervenors are similar to those from the 2009 general rate case. They seek affordable electric service for customers. So do we. They want reliable -- reliability and safety, and so do we. Above all else, we hope that the process will appropriately balance these worthwhile objectives of safety, reliability, and affordability.

The cost of public mandates is growing much faster than the demand for electricity, driving up customer rates, and therefore also need to be tempered by the need for this balance.

Moving to FERC, on Tuesday SCE's 2011 transmission rate filing was accepted by FERC to be effective on January 1, 2012. This will include construction work and progress incentives that were previously recovered in separate proceedings. The formula rate approach is more typically used by peer utilities in FERC rate making, and this would best fit SCE's needs going forward.

We will be updating our revenue request to reflect the order's authorized base ROE of 9.93%, plus a 50 basis-point California ISO adder and roughly 40 basis points on the entire transmission rate base for ROE incentives previously granted by FERC for certain projects. The overall ROE is expected to be about 10.85% in 2012. The exact return will vary, depending upon the mix of construction spending and timing.

Progress also continues on securing approvals for some of SCE's major transmission projects. In May, we received approval from the Bureau of Land Management for the $411 million Eldorado-Ivanpah transmission project, which will service new solar and wind projects.

Interior Secretary Salazar announced on July 14 approvals from the Bureau of Land Management and the U.S. Forest Service for SCE's $655 million Devers-Colorado River transmission project, which will access important solar resources.

In California, much of the transmission rights-of-way cross federal lands, so we were encouraged to receive approvals for these projects.

We and the industry continue to learn to learn lessons from the events at the Fukushima Daiichi plant and from the initial NRC findings from its survey of site and system reliability. We will continue to support the NRC's operational and safety reviews and determine at the appropriate time what, if any, changes in SCE's operations or required investment are needed.

We are also awaiting CPUC funding approval to commence the next round of seismic studies for San Onofre. These studies will utilize the most advanced 3-D survey technologies available and are expected to take several years to complete.

Wrapping up this discussion on SCE, the focus of our capital investment is on enhancing reliability. The focus of our efforts is on operational excellence and controlling costs. In this way, we expect to provide our customers with safe, reliable, and affordable electric service.

Now let me review for investors our strategy for EMG. Having analyzed various alternatives for EMG, we decided the best path was to continue to aggressively work the issues with operational focus and financial discipline to capture the option value for our shareholders that we believe exists in EMG. Central to this strategy is maintaining EMG's separateness, meaning no new capital coming in from Edison International and no distributions going out.

We also continue to diversify EMG's concentration in merchant coal-fired generation. In this regard, a particularly satisfying accomplishment is the completion of financing and commencement of construction on EMG's nearly 500 MW Walnut Creek gas-fired generation project in southern California, which is actually only about 15 minutes from our headquarters.

The estimated project cost is $575 million. EMG won a 10-year contract with Southern California Edison in March 2008, one of four contracts awarded in a competitive solicitation. Since that time, EMG has worked hard to overcome a number of challenges to secure the necessary permits to build the project.

Earlier this year, we identified an innovative approach to solving the permitting issue. It involved the purchase and leaseback of certain gas-fired generation assets owned by AES that will shut down before Walnut Creek starts operations in 2013. Mission allowances for those assets will be transferred to the Walnut Creek project.

California's prohibition of once-through cooling for gas-fired generation stations after 2020, constructing a project of this scale, and an inland location near SCE's major load center will create both current and long-term value for EMG and an important source of safe, reliable, and affordable power for SCE's customers.

Additionally, EMG's diversification strategy has made important progress on the wind development front. EMG's two newest wind projects, Community Wind North in Minnesota and Taloga in Oklahoma, began commercial operation in May and July, respectively. And EMG placed its 29th project into construction in April, the Pinnacle project in West Virginia.

EMG currently has almost 1,900 MW of wind generation in service or under construction in 11 states.

EMG also seeks to develop additional projects from its 3,900 MW wind development pipeline. We continue to work on approaches to secure third-party capital to support the next phase of the EMG's wind energy investments.

With respect to the coal fleet, EMG has met and continues to remain committed to meeting all of its environmental obligations on time, as spelled out in the 2006 Illinois Combined Pollutant Standard agreement and more recent U.S. EPA regulations. We believe that the efforts to identify cost-effective compliance solutions and the financing strategies to support them will serve us well in the long run, even though they present considerable challenges for us in the near term.

We previously stated the draft U.S. EPA HAPs MACT rule is consistent with our 2006 CPS agreement with the Illinois EPA. EMG believes that the U.S. EPA's new Cross-State Air Pollution Rule will not result in material changes in Midwest Gen's compliance plans required to meet the Illinois CPS requirements, including both allocated allowances and capital expenditures.

However, Homer City will be negatively impacted during interim compliance in 2012 and 2013 with the Phase 1 of the Cross-State Air Pollution Rule. This is because a low level of allowances has been granted under the rule to Homer City, and to Pennsylvania generally, in those two years, and by limitations on the extent to which allowances can be obtained and surrendered.

Homer City is evaluating its options for complying with the interim rules in those two years. Depending on how allowance and power prices unfold, we may engage in operational changes and/or reduce dispatch to comply with the Phase 1 of the rule, pending installation of retrofits to comply with Phase 2 in 2014.

Work has already been done and continues on designing SO2 and particulate emissions controls equipment for units one and two so that Homer City will be in a position to meet the Phase 2 January 2014 compliance deadline. Preliminary estimated costs are $600 million to $700 million. Homer City continues to discuss with the lessors the financing that will be needed for the emission control investments.

That completes the major topics I wanted to cover. Now I'd like to turn the call over to Jim Scilacci.

Thank you, Ted, and good morning, everyone. Let's start on page two of the presentation.

Ted has already summarized consolidated results for the second quarter of 2011. I'm going to provide a bit more detail.

During the second quarter of 2010, there were two significant income tax items that affect quarterly and year-to-date comparisons. The first, SCE, EMG, and EIX recorded non-core benefits of $0.43 per share related to the global tax settlement.

Secondly, SCE recorded a $0.12 core benefit for a change of tax accounting method for asset removal. During the second quarter of 2011, the holding company costs were $0.01 lower than last year. This was also mostly due to income taxes. Please turn to page three.

For the second quarter of 2011, SCE earned $0.65 per share, compared to $0.75 last year. Excluding the $0.12 core tax benefit from last year, earnings grew during the second quarter, primarily from rate-based growth.

In our disclosures there are specific numbers, but there are multiple sources of higher revenues, including the utility's 2009 CPUC general rate case, FERC increases primarily related to Tehachapi transmission project, and the SONG steam generator replacement and Edison SmartConnect projects that are outside the customary GRC process.

On an earnings basis, higher authorized revenues are largely offset by increased O&M, depreciation, interest, and taxes. The net impact of these items was a $0.02 favorable earnings increase for the second quarter, excluding the impact of the tax changes I discussed earlier.

Ted has covered the major developments in the quarter, but I want to touch on SCE's capital spending. Capital expenditures totaled $1.6 billion in the first half of the year, consistent with our full-year estimate of $3.9 billion to $4.4 billion.

In addition, the utility's four-year capital spending forecast remains at $15.6 billion to $17.5 billion.

The utility's July 5 rate case rebuttal testimony continues to support capital spending on needed infrastructure and our forecasted rate base. The detailed forecasts are included in the presentation appendix.

With respect to the FERC rate decision that Ted mentioned, this covers about 16%, or just over $3 billion, of our estimated $20 billion-plus total rate base we forecast in 2012.

Turning to page four, you can see the second quarter of 2011, EMG lost $0.09 per share, a $0.01 better than last year. The merchant coal fleet's results were behind last year, primarily from lower realized energy prices and higher operating expenses.

As we mentioned during the first-quarter call, Homer City unit one and two had extended outages to repair faulty piping. Unit one returned to service in April -- in early April and unit two in late May. This obviously affected generation and forced outage metrics.

Midwest Generation's operating performance metrics, which are provided in the appendix, were very good for the second quarter of 2011. EMT, our proprietary trading business, had a solid quarter.

The contribution from EMG's wind portfolio was higher, due to the addition of new projects. Net interest expense did increase from additional wind project financings and lower capitalized interest.

The major difference at EMG during the quarter was DOAA, EMG's jointly-owned gas-fired project in Turkey. Though it contributed $0.05 per share during the second quarter of 2011, while in 2010 EMG received $0.03 per share distribution in the first quarter. Typically, EMG receives one distribution from this project annually.

Pages five through seven summarize our year-to-date results, which are in line with our full-year earnings guidance. I do want to note a couple of things, starting on page six. SCE core earnings totaled $1.33 per share through June 30, 2011, which is $0.05 behind last year. Excluding the $0.12 core tax benefit in 2010, earnings were up $0.07, consistent with rate-based growth from infrastructure investments.

On page seven, EMG's year-to-date losses largely reflect the merchant coal fleet's lower volumes, including the Homer City outage, as well as our lower average realized prices and higher plant maintenance expenses.

Consistent with our expectations, the underlying performance of the renewable energy portfolio was strong with adjusted operating income increasing to $45 million in the first half of 2011 from $29 million last year, reflecting the addition of 500 MW of new projects placed in commercial operations. Availability also improved to 93.7% and capacity factors improved to 39.5%.

Adjusted operating income is a non-GAAP financial measure that includes production tax credits.

Turning now to page 8, EMG sold over 6,300 MW of coal fleet capacity into the most recent PJM RPM auction for the June 2014 through May 2015 period. The modest decline that occurred at Homer City is due to the slightly higher forced outage rates.

We are encouraged to see the capacity prices for Midwest Generation, which improved from $28 per megawatt day to $126. The outcome of the recent RPM auction is consistent with our long-held view that as more coal shuts down, capacity values will respond accordingly.

Turning to page nine, we provide updated information on EMG's merchant coal hedge position. Last quarter, we purposely reduced our hedge position, believing there was more upside to be gained. Thus far, we have benefited from this decision.

We still hold the view that it's better to be less hedged or below the 50% gross margin at risk level that we have previously shared with you. Some of you will notice that we modified the chart to add the change in hedge position from the prior quarter. For 2011, this is a combination of adding new hedges, offset by hedges that were realized during the second quarter.

Footnote one is important to read to understand what happened during the quarter. Hopefully, this change is an improvement. Let us know if it works for you.

As you can tell from the chart, EMG did begin to layer in some new hedges in the second quarter to capture some higher power prices. We added 2.7 TW hours for 2011, as well as 2.4 TW hours for 2012. At June 30, we were hedged 8.9 TW hours for the remainder of 2011 and 9.1 TW hours for 2012.

In terms of coal hedging, Midwest Generation added substantial commitments totaling 800,000 tons for 2011, 3.9 million tons for 2012, 9.8 million tons for 2013, and, again, 9.8 million tons for 2014.

Lastly, in order to answer the obvious question, negotiations with the railroads continue, and we'll let you know when we have reached a final deal.

Turning to page 10, we have now expanded the wind development and financing charts to include the addition of Walnut Creek, EMG's natural gas-fired project that Ted discussed. This slide follows the same format we've been using for several quarters.

As of June 30, we had 185 MW of wind generation under construction and remaining term of commitments of 74 MW. You'll see on pages 11 and 12 the addition of Walnut Creek and the development program sources and uses in capital expenditures.

On July 27, EMG closed the Walnut Creek project financing. As Ted said, we estimate that Walnut Creek will cost $575 million to construct. In addition, financing costs and interest during construction are expected to be $40 million.

EMG's equity contribution is $120 million. The addition of the project financing is expected to fund the remaining capital expenditures for this project.

Lastly, we expect to receive $360 million of U.S. Treasury grants in 2011 and 2012 from our wind projects.

On page 12 is EMG's updated capital spending outlook. As we have indicated previously, we are in discussions with the lessors of Homer City plant about a technology selection, a method of financing for the scrubbers for units one and two, and the facility's environmental compliance for 2012 and 2013. The preliminary cost estimates for the scrubbers is approximately $600 million to $700 million.

The point that Ted and I have covered regarding EMG speak to the key elements of our strategy to realize EMG's option value, as summarized on page 13. We continue to see the market giving no value in our stock price for EMG, but we believe there is real option value being preserved through the actions we are taking and with the potential for realization of that market value if there is timely recovery of power prices.

I'll close with a brief comment on our 2011 earnings guidance. Ted has already commented that our full-year core earnings outlook would place EIX at the high end of our $2.60 to $2.90 range. We have noted on slide 14 that our key assumptions have not changed, other than to update for forward prices as of June 30, and exclude future discontinued operations and non-core items. We expect to update our guidance when we report third-quarter results.

That concludes my comments. Operator, let's move to Q&A.

(Operator Instructions). Jonathan Arnold, Deutsche Bank.

I've a question on Homer City. In talking -- I know that you mentioned that to 2012 and 2013 you might seek to comply with the CSAPR rule by running the plant less, I guess. Just how will you kind of address the, I guess, covenant issues that might come with that? I guess, did you have a similar situation earlier this year with the outages?

Jonathan, I'll start it off, then I'll pass it over to Pedro and Maria. Given right now we're trying to work through how exactly we're going to operate in 2012 and 2013, and we're trying to work up a plan, and with a plan, then you can go through and determine what the financial ramifications would be of that plan.

And at this point in time, I don't think we have clearly in mind how we're going to operate Homer City, given the new rules. We have to determine what the emissions credits might cost, how many we could actually achieve, and what the approach we're going to use in terms of how we might modify the operation of plants.

So I'm going to stop there and look over to Pedro and Maria to see if you have anything else to add. I think it's just early in the process for us to really give you a good sense for what we're going to do.

Jim, I would agree, and Jonathan, the one comment I would make is that we are not only looking at reducing the level of dispatch, but we're looking really at all operational options, some of the other things that we can do to improve the chances -- the ability to comply under CSAPR. So, really, looking at a whole universe of things, and once we have that plan in place, we can work through the full implications on the financial side.

Jonathan, one last thing I'll add to, and part of the discussions with the lessors would be exactly what things we'd need to do in order to operate efficiently for 2012 and 2013, and then looking forward to 2014 as we go into operations with the new scrubbers.

Understood. Could you maybe clarify a little bit what is the -- you're obviously sold forward in the capacity auctions for those periods. What are you actually required to deliver in terms of performing under those short-capacity positions?

Again, that's -- you can see the numbers in the disclosures as far as what we've actually sold, and there are requirements under the agreement with PJM. So I guess where you're going, if you fail to deliver there are penalties, but you also have the ability periodically, in the auctions, to adjust your positions, either up or down, depending upon your needs.

Okay. But you wouldn't have to be available 24/7 effectively, either. Is there -- can you just remind us what the commitment is?

I'll look over to Pedro.

(Multiple speakers) the -- again, when we sell into the PJM auctions, it's a requirement to make the capacity available.

The point Jim was making was that commitment can be adjusted through the residual auctions that are held. And then, PJM also has -- in the worst case, if capacity that is committed doesn't show up when it is called on, there are penalty provisions called for in the PJM agreements.

So, there are basically multiple stages to this. First, residual auctions and being able to true up positions, and then through capacity and [odd] materialize, then having the exposure to the PJM penalty provisions.

Thank you. Could I just ask one thing on the utility? Eldorado-Ivanpah, it looked like the investment opportunity there went down $70 million-odd was -- between the last disclosure. Did something change with the scope of the project?

No, when the PUC approves those, Jonathan, this is Ron, at that stage they often will reduce your contingency, pending final engineering. And then, you are allowed to update your costs at a later date when final engineering is complete.

So that was what -- this was just the contingency [being].

That's correct.

Dan Eggers, Credit Suisse.

Just on the utility side, Ted, I thought it was interesting, your comment about policy outpacing other issues as far as demands on customer bills. Is there an appetite for change in California in any of these rules or is this the inevitable nature of California at this point?

I don't think anything is inevitable. I think the key here, and we are becoming more active in this, is to explain to policymakers and to the public that the effect of such a dramatic increase in policy -- public policy mandates ends up driving up costs. And if electricity demand isn't keeping pace with those costs, the natural outcome is higher customer rates.

So, it's a pretty simple equation, but you kind of have to put all the pieces together in order to see it clearly.

So, this is what we've been talking to the commission about. It's what we've been talking to public policymakers, elected officials, and the public.

And I guess just on the generation side for compliance at the EPA rules, when do you guys think you're going to have a more complete plan kind of on what strategies you're going to deploy to share with us? And then, what's going to be the decision tree right now on Homer City as far as getting the money together or the decision to get the money together to put the scrubbers on?

I think the answer for both is probably around the same time.

We've said previously that we would look to update our environmental compliance costs at the end of the year, once we have a final HAPs MACT rule. And that timing is coincident with our expectation for Homer City, too. It's key that we work through our issues with the lessors and think about getting into construction at Homer City by the early part of next year, so it would take us two years to construct the facilities that would be online in early 2014.

So the general view, Dan, is we should be -- in the fourth-quarter results, we'll be updating for all the current events.

So the scrubbers will only take two years to build, so you guys will realistically meet the 2014 timeline, even if the decision is not done until the first quarter?

Yes, and that's what we've said in the disclosures. That's why we're doing some preliminary engineering right now in order to be in the position that we can -- if we reach agreement with the lessors and arrange for financing, then we'll be right into construction early in 2012.

Travis Miller, Morningstar.

Another question on the generation side. If you guys maintain the no capital in/no capital out there to EMG and you decide to go with the environmental controls on Homer City, the $600 million or $700 million, how does that affect your wind portfolio growth opportunities and any other kind of generation opportunities at EMG?

Really what we're looking to do is we're looking to the lessor and potential third-party investors to finance the Homer City environmental upgrades. Full stop.

On the renewable generation portfolio, part of Ted's comments and what we stated previously that we have about 74 MW of remaining commitments for wind turbines and we are seeking third-party potential investments, equity, to go beyond our existing commitments for wind turbines. So, that's two separate financings we're looking at in order to continue our wind business and make the environmental upgrades for Homer.

Then a quick follow-up on that. Does the -- I guess described here the obligations and rights for that lessee/lessor relationship. Do the lessors have the obligation and a right to decide, essentially, whether to retrofit and/or close the facility?

I think the easiest way -- it's very, very complicated. There are extensive agreements governing the rights under Homer City and how we operate and our relationship with the lessors.

I think the simplest thing I can convey to you is that it's complicated, and we are just working for a consensual arrangement with the lessors in terms of how we're going to make these upgrades and how we are going to operate post-upgrades in 2014 and beyond.

I think it's also important to note, and we've stressed it before, Homer City is nonrecourse within the EMG complex.

So just to summarize, the lessor has the -- the lessor would be on the hook for the capital or is there a chance that you guys also would be on the hook for the capital?

Again, I'd say it's nonrecourse, so if we don't have the capital resources to do it, then we would not go forward with it on our nickel. The lessor has a choice to make as to what they would do, and as we've said, we're really working on this as we're working with the lessors to find third-party financing for the retrofits.

Steven Fleishman, Bank of America Merrill Lynch.

You just answered one of my questions, but just, Jim, on the comment that you are tracking toward the high end of your range for the year. Could you just clarify what exactly is driving you to the higher end of the range? Is it better performance at EMG? Is it both?

I think it's a little bit of everything. I'm not going to be specific as far as tick and tack where it might show up, but we are seeing higher prices and we've upped our hedging at EMG. You can see that from the numbers we've provided.

The holding company is tracking a little ahead, year-to-date. SCE is tracking a little bit, so it's here and there and everywhere, and we'll update for the -- when we get to the third quarter.

And then, I guess, just on the transmission decision, so that ROE affects the whole transmission rate base?

Yes, we just recently had that FERC decision. Let me just clarify here. The return on common equity that Ted talked about in his script, it really affects things going forward in 2012 and beyond. It doesn't affect what we're doing for 2011. So we just need to separate the two.

And it's a slight reduction. We're at 11.5% we expect for 2012, and we're at 10.85% based on the current numbers and the current mix of transmission spending for 2012.

Ali Agha, SunTrust.

I wanted to clarify, Ted or Jim, comments. I've heard a number of times you guys talk about preserving the option value at EMG and the actions being taken. Just to take that a little step further, what kind of timeframe do you have in mind reserve that option value? Is that an indefinite sort of plan or when do you reach a decision point that suggests to you, perhaps, the option value is not going to be recognized in the timeframe you have in mind? What kind of timeframe are you looking at?

Ali, this is Ted. I'm not the most patient person, but I think, generally speaking, so long as we see and believe that there is option value, we'll continue to work aggressively for that.

Clearly, we'd like to see it develop sooner than later. We'd like to see it reflected in the stock price sooner than later. I think that's mostly about picking off the uncertainties and being able to show investors more clearly where that equity value is that we see.

So, that's what all of the efforts are focused on, trying to accelerate the clarity and make that visible to investors.

So, I mean, end of 2012, if you're having the same conversation, Ted, is that a fair time to be thinking about this or it could be even longer?

I appreciate your interest in trying to pin me down to a specific time, but I really can't do that. I think, again, it would come back to so long as we believe that there is option value there, we see how we can obtain it, then we'll continue to work hard to bring it forward. We don't have a specific timeframe in mind.

Second question, if I could. You've talked about potentially bringing in some third-party investors in the wind portfolio. You talk about third-party financing for the Homer City upgrade. I'm assuming that's different from an equity infusion, but correct me if I'm wrong.

But when you look at the Midwest Gen and Homer City portfolio as well, would you have an interest, even in this environment, to perhaps bring in third-party equity ownership there to bring out some of that value? Is that a viable strategy in this market?

Ali, I think it's probably wisest for us to not try to speculate a lot on those pieces. I think we've tried to steer the path that we can in this discussion this morning.

The Homer City piece is nonrecourse. We are seeking third-party financing. That's critical. That could either come from the lessors or it could come from third parties. And I think we've got a good constructive effort underway with the lessors to find the third-party financing. So, that's the primary focus.

In terms of asset sales, which is the way I interpret your question, we have a policy of not really talking about those things unless we have something specific to announce.

Hugh Wynne, Sanford Bernstein.

I had a question regarding Midwest Generation. You've pointed out that you believe you can comply with the Cross-State Air Pollution Rule based on the plans you're already putting in place to comply with the Illinois EPA agreement, and you've given us the cost, the capital cost, of doing so. What would be the impact on operating costs of the dry sorbent injection technology?

Hugh, it's Jim. I think you're just at a timeframe where -- when we look to actually start spending on DSI or our Trona approach, that's really beyond the horizon where we're going to give guidance. Clearly, there, it would add to operating costs. There are ways you can estimate it, but we haven't been public as of yet in terms of how much that might be.

Could you tell us what percentage of hours that operating cost might be recoverable, or reflected in the price of power and therefore recoverable, as opposed to when it might not?

That's a tough question because it's going to be unit by unit, and it depends on the timeframe from which we're actually going to install the DSI on the various units.

So obviously if we were to upgrade Waukegan 7, and that would be one of the first, we're looking at moving ahead the Powerton station, and then it would depend on how often coal is on the margin relative to natural gas. Those are really a whole bunch of complex numbers that I can't even begin to estimate here.

But there is -- obviously, we're going to have to work through that as we get -- go forward in time, and we're going to have to come up with earning guidance as we get to that point in time, but that's a couple of years out, as you know.

Michael Lapides, Goldman Sachs.

Hi, Ted. Can we come back to the transmission item for a second? I want to make sure I follow this. Can you update us on what the transmission rate base was that was part of the case? And am I thinking about it correctly that the rate base prior to the case continues to earn the prior 11-plus ROE, and anything after the case, including some of the projects like Tehachapi, earn the 10.85 ROE?

I'm going to let our transmission expert, Jim Scilacci, give you the answer on that, Mike.

Then I'm going to turn it over to Linda Sullivan, if I screw it up.

So, the way we're putting it right now for 2011 and for guidance purposes, we're using the simplified approach and using our total rate base times 11.5% times the 48%. So we're not moving off of that.

So that's what -- for directional purposes, that's what you should be using, Michael. It gets more complicated, and we haven't given -- we haven't broken out FERC transmission pieces for 2011, so we're going to leave it with the simplified approach.

For 2012, and I said in my script, our transmission rate base is about $3 billion, plus or minus. And that is the piece that would have the lower expected return, which we are estimating right now, based on the mix, to be about 10.85%.

On all of the transmission rate base for 2012?

On all of the transmission.

Including (multiple speakers) -- so, okay. Including incremental projects, as well as the rate base that was in service through the end of 2011?

Yes. Now it's going to get a lot more complicated because you're going to have different rates of return on different pieces of FERC rate base, and we're going to try and simplify this and find some way to go forward on an aggregate basis, instead of trying to find that this project has an X return and Y project has a Z return.

So we're going to try to keep it on an aggregate basis. But we'll have to figure that out for the end of the year as we give guidance for 2012 and beyond.

Okay, and the major projects listed on page 28, the ROEs for the bulk of those, especially the big ones like Tehachapi and Devers, have already been set by the FERC, so I could follow up with Scott on just making sure I'm modeling the right numbers there.

That's correct.

Brian Chin, Citigroup.

Going back to your answer on John Arnold's question on Homer City and the residual auctions for RPM, could you just talk a little bit about how mechanically would that work? Is it that you'd go into the residual auction and try to buy replacement capacity to try to reflect the two units at Homer City that may not be available the entire time for 2012 and 2013? Is that how it would work?

Yes, and that's exactly the case. Now, again, we're not certain we have to do that. We haven't gone through all the mechanics of how we might operate under the new rules.

But what you just suggested is the way that we would go about it. And we actually do that periodically to the extent that you may need to make fine-tuning adjustments, and you'll see it periodically in our capacity charts. There will be slight additions or deletions, depending upon how we think we're going to need to operate.

Right, right. And then, historically, when you've made those slight adjustments, obviously the cash impact happens during the settlement period. But then, do you record the earnings impact when the auction -- residual auction happens or does it all just sort of happen during the settlement year?

Frankly, I don't know the answer to that question, so I'm going to have to follow back with you on mechanically how that works. You would think that we would record the revenues as earned, and so if there is a change, then we would reflect it that way. But we will confirm back.

Michael Goldenberg, Luminus Management.

I wanted to follow up on Homer City. As far as 2012, you said that there are several options. You can reduce production, you can -- do other things. Throughout the year, because I -- from what I understand, the penalty won't be known until the end of the year. How do you go through the year making those decisions without knowing what the end result is until the end of the year?

Well, let me just go through the litany of what we might do, so we're clear.

You could change your operations. You could potentially change the way you operate the plant in terms of the fuel. You can -- so you can have higher- or lower-quality sulfur content. We have the ability to do that, but we're going to look at that carefully. We haven't made any decisions.

Now, how the penalties are determined, I'm going to pause and look to Pedro here and see if you have anything -- if there's anything else here we should add.

And I'd like to clarify, are you thinking about penalties that we were discussing earlier in terms of capacity at PJM or are you thinking about EPA penalties for the allocation?

EPA, EPA.

Okay. So, now, I think we -- we are still working our way through the rule on how this will apply.

As we have disclosed, the allocations that we were granted for Homer City for 2012 and 2013 in the rule are just short of 26,000 tons for each of those years. If you look at our historical -- for 2010 emissions, that was more around 113,000 tons per year, in that ballpark.

There are -- it's a very complex rule and it includes not only those allocations for plants, but it also includes limits on how many allowances that are purchased in the market can be surrendered. So there's a lot of [amounts] still to work through here in terms of how will other players respond in the market, what number of allowances will be available for purchase in the market other than compared with the state-level variability limits, and how many allowances can be surrendered. So, still working on ways to putting all those pieces together.

But my question was, assuming you don't -- for example, switch coal. Is there a sort of seasonality of output that would be more efficient than something else that you have considered you maybe can explain to us?

Well, the simple answer is yes. As you can imagine, there'd be seasonality of output and that could drive value. That's probably wisest to stop there because we're still working our way through the math of what would optimum operations for Homer City look like in the face of limited allowances.

So, I think you're getting to the nub of the math problem and conceptual issue that we're working our way through right now.

Michael, you've got a good question there. Clearly, you're going to want to operate during the high-margin hours. And then, how you optimize the design of your operations around that is the key, and that's the math we're going through right now to try to figure that out.

And on fuel, do you both have rail and additional storage because of lower BTU to burn lower-sulfur coal, or is there storage problems at the plant?

At this point, I'd rather just comment, we're looking at all these options and not go into more detail because we're really working our way through the issues right now.

Raymond Leung, Goldman Sachs.

A couple of things, just switching a little bit on gears. Of the guidance that you've provided on EMG, how much of that is from trading operations? And what have you seen on that end?

If you go back in the deck, it shows the numbers that we had included in our guidance for EMMT. I think the number -- I'll confirm it -- I think it's $70 million to $100 million -- (multiple speakers)

$50 million to $100 million.

$50 million to $100 million. We adjust it. We showed at the beginning of the year a little higher number, then we shifted the Homer City-related numbers over to Homer City, so we dropped it from $250 million to $100 million (multiple speakers) in the year to date. (Multiple speakers)

And that's on a pretax basis, too, so you're clear. That is not an after-tax number. And (multiple speakers) we did show here in our disclosures where the trading business is coming out. It had actually a pretty good second quarter.

Great. Two other things. You show about $360 million in Treasury grants. Are you -- I think -- in the footnote, you indicated 2012 for that, or are you expecting any of that in 2011 at all?

A small piece is 2012. The majority of it comes in in 2011. The footnote should be -- yes, I think there's just a small piece that comes in (multiple speakers) -- the majority (multiple speakers)

Any issues with, you think, getting those proceeds on time?

No. We've been -- we've already received a number of them. There is a technical hoop you have to jump through, and once you do that, it actually comes in fairly consistently.

Okay, and then, is there any bonus depreciation for you guys? Can you sort of outline -- I know EIX may have to provide the taxable income to SoCal Ed, and sort of maybe outline what potential timeline that could help you guys in terms of that point -- (multiple speakers) in cash?

(Multiple speakers). Yes, now this is confusing because you have so many different entities that are at play here.

We've said that EIX is in an NOL position for 2010 and likely for 2011 and potentially for 2012 because you continue to have bonus depreciation in 2012, and that's going to cause a challenge for EMG to monetize tax benefits during that period. And so, after you reach -- you go out of the NOL period, EMG -- after the utility goes out of the NOL position, then EMG then could monetize tax benefits, and we've said that could take several years.

So, let me pause there and ask you if the question still is clear in terms of -- it's not clear right now in terms of where you want to go with it.

I guess, what do you expect potentially down the road from bonus depreciation?

Well, if you expect it -- we're going to have it for next year, for 2012, at 50%. So EMG would be able to take advantage of that for projects in construction for that year.

Beyond 2012, given all that's going on in Washington, I think I'd be hard-pressed to believe that they extend bonus depreciation for another year. It's been a tremendous source of cash for the utility for the last several years. But those are political judgments, and we'll just have to see where things in Washington go.

Okay, and just last thing. Any more color -- I know you guys keep talking about renegotiating the bank lines, and you've always said weeks. Can you talk about maybe what potential hurdles there may be that sort of continue to sort of -- as it sort of continues to play out?

Our intent is to ultimately put in place a credit facility at EME and Midwest Gen. We're still working through what the amount would be.

We would clearly look to reduce from the 1.1 we have right now to something below that, and we're just going to go through the process with the banks. Obviously, the extension of the revolver beyond 2013 is linked to our process for determining what we're going to do with that maturity in 2013, mid-part. And so those are things we're working through together.

So I don't have a timeline. We're clearly -- we're focused on that and it links back to the option value, too, in how we extend the running board to resolve the 2013 maturity, so we extend that option value out.

Do you think that's an 2011 event or 2012 event?

I won't speculate on when that's going to occur, but clearly we're thinking about it real hard.

Jason Mandel, RBC.

Thanks, guys. Just a quick follow-up question, again, on the Cross-State Air Pollution Rule and the impact on Homer City. You've given some pretty good details. That's helpful. But for unit three in particular, is there any reason to expect that that unit can't just run flat out without any curtailments?

I think unit three, given that it's already scrubbed and has an SCR, it would operate in a normal arrangement.

And then, for -- so we're talking about curtailments for units one and two. And then, in the event that financing is able to be raised for scrubbing, so the $600 million to $700 million, I presume we're talking about scrubbers, and then, what kind of timeframe for outages would you expect at those units during construction?

We haven't said yet because, obviously, you're going to build the scrubber. It's really a standalone unit, then you would need to cut it in through some type of outage that you would normally take and plan for.

So, that's something that's down the road. It would be probably in the latter half of 2013 before the unit would go operational in 2014, but we would plan accordingly for it and schedule our overhauls to correspond with that.

Perfect. And then, if I could just follow up, one last question back to the tax-sharing agreement, given that that agreement has generated some pretty good cash for EME over the last few years and may not for the next few years, you pointed out the difficulty in monetizing. Is there anything being contemplated in terms of figuring out some way to monetize that, either externally or internally to the total enterprise?

I think it's premature to talk about what we may do there. We're looking at it, and that's all wrapped up in the discussions we'll have with our banks in terms of what we might do next.

Thank you. That was the last question. I will now turn the call back over to Mr. Cunningham.

Thanks very much, everyone, for joining us this morning, and please do follow up with Investor Relations if you have any further questions. Thank you.

Thank you. That does conclude today's conference. You may disconnect at this time.