艾索倫電力 (EXC) 2013 Q2 法說會逐字稿

Good morning, my name is Kalia and I will be your conference operator today. At this time I would like to welcome everyone to the second-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions). Thank you. I would now like to turn the call over to our host, Ravi Ganti. You may begin your conference.

Thank you, operator, and good morning, everyone. Welcome to Exelon's second-quarter 2013 earnings conference call. Thank you for joining us today. We issued an earnings release this morning; if you haven't received it the release is available on Exelon's investor website.

The earnings release and the other matters we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties and the actual results could differ from our statements. Please refer to today's 8-K and (inaudible) other filings for a discussion of the factors that may cause results to differ from management's projections, forecasts and expectations and for a reconciliation of operating to GAAP earnings.

Leading the call today are Chris Crane, Exelon's President and CEO; Ken Cornew, Exelon's Chief Commercial Officer and President and CEO of Exelon Generation; and Jack Thayer, Exelon's Executive Vice President and Chief Financial Officer. They are joined by other members of the executive management team who will be available to answer your questions at the end of the prepared remarks. We have scheduled 60 minutes for this call. I now turn the call over to Chris.

Good morning and thank you for everybody joining. We delivered on our financial and operational expectations this quarter and the markets lower commodity prices continue to challenge us both in the near-term and the outer years. Ken Cornew will provide more detail on both the power markets and the capacity markets.

Overall the prices that were received in the RPM auction this quarter were disappointing but not devastating. We can't control or influence the markets; we can control our actions, business practices and decisions. We continue to leverage on our core competencies; our reliability and efficiency provides a competitive advantage. By resizing the dividend we have strengthened our balance sheet and now have a sustainable dividend and the ability to invest and grow even when prices move against us.

Moving to the financial update, the second-quarter operating earnings were $0.53 a share, within the guidance of $0.50 to $0.60 a share and Jack Thayer will discuss the drivers around that. We are providing guidance of $0.60 to $0.70 per share for the third quarter operating earnings and reaffirming our full-year guidance of $2.35 to $2.65 per share.

Operations remain strong. While the full-year gross margin expectations at Constellation are lower,as you can see from the hedge disclosure, the full Company impact has been offset largely by reductions in cost and strong utility performance and both Jack and Ken will provide more details around that.

Moving to operational excellence, on slide 1, we are on track for a very good year operationally. Our generation fleet performed well this quarter; nuclear ran at a 92.8 capacity factor in the second quarter despite our refueling outage days, which is normal, and for the loss of off-site power at LaSalle in April. Year-to-date performance for the fleet has been excellent with a capacity factor slightly under 95%. Our agreement with EDF provides an opportunity to do what we do best, run the CENG plants safely, reliably and more efficiently.

Fossil and renewable fleets have had a strong quarter as well. Fossil and hydro dispatch match rate was at 99.1%; solar and wind energy capture were at 92.4%. And the utilities had very solid performance thus far this year. All three utilities to date are in top decile safety performance and a continuing improvement in consumer satisfaction index year over year.

On the regulatory advocacy side in Illinois, Illinois Senate Bill 9 was enacted this quarter. It enables us to start executing grid modernization plans including installation of smart meters to improve reliability. We filed rate cases at both ComEd and BGE and this will now be a regular practice as we have accelerated our capital into those systems.

The RPM auctions, as I said, Ken will provide some more context around that. But like all competitive generators in PJM we were disappointed with the May results. Looking back on RPM and the auction process, it is a 12-year-old process. From time to time we have had issues arise around the process that have required us to go back to the stakeholder process and make amendments.

We will be working with PJM and fellow stakeholders on improvements and recommendations to address the increased reliance on planned resources and also supporting PJM's effort to enhance the MOPR rules as well as rules governing demand response.

On the growth and investment side, we are bringing new megawatts online, growing our rate base with smart grid investments. We've installed 99 megawatts of solar at our AVSR solar facility year to date and expect to add another 102 megawatts to complete the project by year-end.

We are adding approximately 46 megawatts to our wind portfolio in 2014 with our Beebe project in Michigan. The smart meter installation projects are well underway this year at all three utilities. For 2013, BGE has installed 287,000 meters thus far, 980,000 are expected to be installed by year-end.

At PECO we have 364,000 meters in year to date with 562,000 expected by year end. And ComEd's smart meter deployment begins in September with 60,000 meters expected by year-end. And we will continue to look for other opportunities to grow value.

As we talked about before, financial discipline is key to our management model. Our decision to cancel the EPUs at LaSalle and Limerick demonstrate our continued focus on financial discipline and value return. We can return capital in other places elsewhere in the value chain to realize value at a sooner pace.

We are on track to achieve synergies associated with merger including $305 million of synergies in 2013 and a run rate of $550 million of synergies beginning in 2014. And we continue to look to pull cost out of the business across all businesses.

The wholesale market and the competitive retail market are challenging. The impact on our gross margin expectations through 2015 has been noted. We are aggressively taking actions to offset these challenges by taking on additional cost-cutting to focus on each business and optimize the portfolio. Now I will turn it over to Ken Cornew to provide some more specifics on power and gas markets in our retail business.

Thanks, Chris, and good morning, everyone. As Chris mentioned, I will start with the recent PJM capacity auction, market trends and then provide an update on the Constellation business. As Chris said in his opening remarks, the results of the May capacity auction were disappointing. The results were lower than we and many others, including most of you on the call, had anticipated.

As you know, this was largely due to the 90% increase in capacity imports over the previous auction and the amount of new generation that cleared. The volume of new generation that cleared in the auction is surprising given the lower clearing prices. We do not believe that it is reflective of the long-term capacity revenues needed to support new generation development.

10 gigawatts of coal did not clear in the auction, a record level, and the amount of coal offered in the capacity auction continues to decline from 67 gigawatts in 2013-2014, to 59 gigawatts in 2016-2017. These two facts bolster our view that more than 20 gigawatts of coal will be retired in PJM by 2016.

Slide 3 depicts the fundamental changes to the PJM supply stack that have occurred over the last few auctions. As you can see from the chart on the top left, the existing PJM generation stack as it existed in the 2013-2014 planning year has become a smaller percentage of the overall capacity. There is a large amount of planned new generation expected to be online by 2015 and 2016. In the 2016-2017 planning year imports, demand response, and energy efficiency combine for nearly 22 gigawatts of PJM capacity.

When we factor all of these changes to the supply stack along with other input assumptions such as modest load growth projections and current forward fuel prices, we continue to see upside compared to the current forward PJM power markets. Like all of you, we continue to wait and watch for developments on some of these new planned resources. Needless to say, if the new planned resources do not materialize it may create additional volatility in the market and potential for upside in power prices beyond what is in our current forecast.

Additionally, the retired coal units are being replaced by some supply resources which have a very different dispatch profile. This can lead to increased volatility in the spot energy prices. We have many issues to consider from this RPM auction. Will the required transmission for imports get built? Will the new generation get built at these prices? At what price does demand response participate in the energy market? Do these trends continue at the next auction or do they reverse?

We've seen anomalies in the RPM auction results before and have successfully used stakeholder process at PJM and FERC to improve the auction process. The MOPR issues of the 2015-2016 auction we were largely fixed by FERC as a result of the stakeholder process at PJM. Exelon intends to work with PJM, other PJM stakeholders and FERC in reviewing the auction results and considering potential changes to market rules to address PJM's increased reliance on planned resources.

Slide four provides an overview of how we've positioned the portfolio to benefit from our fundamental views. Forward power prices have fallen since we last updated you on the Q1 call. In particular West Hub and NiHub decreased by $2.90 a megawatt hour and $2.68 a megawatt hour in 2015 respectively. Natural gas prices decreased approximately $0.16 an MM BTU in 2015 which has caused some of the decline in power price.

We continue to see a disconnect in forward heat rates compared to our fundamental forecast given current natural gas prices, given expected retirements, given the new generation resources and given our modest load growth assumptions. We've acted on this view and have widened our deviation to ratable across our entire portfolio in the past six months which has reached approximately 8% under ratable for 2015. The actual deviation in a pure underlying power position is even greater when options across commodity hedges are factored in.

Let me address the following question -- what does this market upside really mean in terms of earnings or gross margins for Exelon? To put it simply, it depends on the unhedged position of our portfolio at the time the upside is realized in the market. The sooner the upside is realized the greater the impact. Our fundamental view remains that there are $2 to $4 of upside still to be realized in the PJM markets. This market upside will have a gross margin impact of around $550 million on a fully open basis.

We will continue to evaluate the amount of upside we see in prices due to our views and carry position that allow us to benefit as much as possible from the realization of these views.

Now I'll turn to Constellation's results for this year and the outlook for the next two years. There are increased challenges in the business from all sides. As I mentioned before, power prices are lower, forward heat rates are lower and there continues to be pressure on the retail segment from aggressive competition and reduced volatility.

As you can see on slide 5 for 2013 the total reduction to gross margin from the last quarter is $150 million. There are three elements equally contributing to this reduction. First, we had lower-than-expected generation in the quarter due to an unplanned outage at our LaSalle plant and delays in the online date for portions of our AVSR solar project. Despite these delays there will be an offset in terms of depreciation expense for AVSR in the GenCo financials.

The second element is under collection of revenues from PJM financial transmission rights or FTRs, otherwise known as congestion rights. For those of you that monitor PJM, you will likely know this under collection situation or entities that own these congestion rates are being paid significantly less than their full value.

Third, the remaining is due to a $50 million reduction in our new business targets for the year largely attributed to reduced expectations in our wholesale gross margin. In 2014 and 2015 our disclosure indicates a reduction of $250 million and $400 million respectively in our hedged gross margin. The reduction in power price and the resulting impact of our unhedged generation contributes to the bulk of this drop.

As you've heard us say for the last few quarters, the retail space is extremely competitive and challenged. We have remained disciplined and have not gone after volume for the sake of volume but have maintained appropriate margin on our sales. Due to this continued competition and limited volatility we revised our estimates from both a margin and volume perspective. Our expectation for the weighted realized margin of our retail business still remains at the lower end of our $2 to $4 a megawatt hour range. Our recent retail C&I origination margins are slightly below that $2; however, we expect to be in that $2 to $4 range in the longer-term.

Additionally, we are lowering our volume expectations from what we published at EEI by 15, 20 and 25 terawatt hours for 2013, 2014 and 2015 respectively. We are still optimistic that we can grow the retail business, but, given the overall competitive environment we have seen over the last 18 months, we have chosen to be more conservative in our volume estimates.

To mitigate the impacts of lower gross margins and new business targets, we continue to take a hard look at our costs in optimizing our processes. We have reduced the Constellation O&M budget by roughly $50 million for 2013, 2014 and 2015. We will continue to look for additional opportunities to further reduce our operating costs through process and system improvements.

In total ExGen is reducing its O&M by $100 million in 2013 which includes the $50 million of O&M reduction at Constellation I just discussed. We are targeting O&M reductions in 2014 and 2015 that will result in a roughly flat CAGR for ExGen. I will now turn it over to Jack to review the full financial information for the quarter.

Thank you, Ken, and good morning, everyone. I will review the second-quarter financial results, our third-quarter guidance range, key events of the quarter at the utilities and our balance sheet and cash flow outlook. I will start with our financial results on slide 6.

As Chris mentioned earlier, Exelon produced results consistent with our expectations. Operating earnings for the second quarter of this year were $0.53 per share, within our Q2 guidance range of $0.50 to $0.60 per share. We reduced O&M at ExGen and realized the favorable impacts of SB9. These positive drivers are offset by unfavorable performance at Constellation. This compares to earnings of $0.61 per share during the second quarter of 2012.

The key drivers of the quarter-over-quarter difference were lower realized energy prices at generation; decreased capacity pricing; and higher nuclear fuel costs. I will go into greater detail on the quarter's drivers in a few minutes.

For the full year we are reaffirming our guidance range of $2.35 to $2.65 per share. Despite the reductions in gross margin as seen in our hedge disclosures, we are confident that we can deliver on our full-year guidance range. This is due to the passage of Senate Bill 9, the outcomes of the rate cases at ComEd and BGE, the full $100 million of O&M reductions at ExGen, and depreciation offsets due to the AVSR delay. We will continue to look at additional opportunities to improve our cost structure and streamline the business. For the third quarter we're providing a guidance range of $0.60 to $0.70 per share.

Turning to Exelon Generation on slide 7, ExGen's results were $0.15 per share lower quarter over quarter primarily driven by lower revenue net fuel due to lower realized energy prices and lower capacity prices. This was partially offset by lower O&M costs due to merger synergies and lower income tax due to investment tax credit benefits from AVSR.

Before I turn to the quarterly earnings for the utilities on slide 8, let me provide a brief update on our load forecast. In general, the outlook for 2013 is improving as economic conditions continue to strengthen. Both ComEd and PECO are forecasting positive load growth for 2013 and BGE would be positive after removing the negative impacts of RG Steel. More detail on utility load can be found in the appendix on slide 19.

ComEd's earnings increased $0.06 per share compared to the earnings of the prior period last year. This is primarily driven by the reversal of the write-down of a regulatory asset we reported in Q2 of 2012 based on an ICC order we received in May of that year. We're also seeing the benefits of higher distribution revenue due to higher allowed ROE and the impact of SB9. These are offset by unfavorable weather compared to the second quarter of 2012 where Northern Illinois experienced above average heat in June.

PECO's earnings decreased $0.01 per share compared to the earnings in the prior period last year. This decrease is a result of the premium paid for redemption of PECO preferred stock during the quarter. Higher O&M costs for the quarter due to inflation were offset by lower income taxes. BGE's earnings increased $0.01 per share compared to the earnings in the prior period last year. This is related to the increased electric and gas rates that were received in a recent rate order.

Second quarter was a productive time for the utilities in the regulatory and legislative arena. During this quarter BGE filed a rate case and in Illinois the legislature overrode Governor Quinn's veto of SB9. The impact of SB9 is expected to be $0.01 per share in 2013 and $0.04 per share in 2014.

In late May ComEd also amended its rate case to reflect the passage of Senate Bill 9. The amended filing requests an increase of $359 million which is $48 million more than the pre-SB9 filing. This reflects actual 2012 expenses and investments and forecasted 2013 capital additions to our distribution network. We expect a decision by year end with the new rates going into effect in January 2014.

In May BGE filed a rate case with the Maryland PSC asking for an increase of $101.5 million for electric and $29.7 million for gas. We expect the final order in mid-December with new rates going into effect shortly thereafter. We are optimistic that we can build upon the results of our last rate case.

We continue to target a 5% to 6% growth in rate base for all three of our utilities and have set a target of 10% earned ROE by the end of our planning period. In the appendix we've updated our rate base and ROE targets for the utilities. As you will see, we have maintained all three utilities' long-term equity target ratio of 53%.

However, in the short to intermediate term we believe an equity to total capital ratio of 46% allows ComEd to effectively earn on all equity invested in both transmission and distribution businesses. Given our current situation, a capital structure at ComEd with more equity would result in less than optimal earnings in the transmission business.

Slide 9 provides an update of our cash flow expectations for this year. We project cash from operations of $5.6 billion. This is down from last quarter by about $270 million. Primary drivers of the decline include lower net income at Exelon Generation related to the revision in our full-year portfolio targets and timing of tax refunds at ComEd originally anticipated for 2013 that are now expected in 2014.

Our CapEx forecast has increased by $125 million from last quarter mainly due to accelerated AMI deployment at ComEd, movement of upstream spend from the first quarter of 2014 into 2013 and the addition of the Beebe Phase 1 project in the wind portfolio. Our current five-year plan includes $16 billion in growth CapEx with approximately $13.5 billion of that at the utilities where we have the ability to earn a stable rate of return.

We have upsized our planned ComEd long-term debt issuance by $100 million from last quarter due to the aforementioned delay in tax refunds. PECO's anticipated $550 million issuance and $500 million retirement contemplates termination of its $210 million accounts receivable facility which matures on August 30 of 2013.

Last month we received commitments from all banks within the BGE, PECO, Exelon Corp. and Exelon Generation core credit facilities to extend the maturity date one year. With the ComEd extension executed early this year, all $8 billion of our core credit facilities are now extended into 2018. This extension provides for refinancing flexibility to Exelon as new banking regulations are implemented over the next several years.

Yesterday we announced that we had reached an agreement with EDF to operate the CENG plants. As part of the agreement Exelon will provide CENG with a $400 million loan at an interest rate of 5.25% which will be used to provide a special dividend to EDF. Once the loan is repaid Exelon will receive a preferred dividend from CENG.

The agreement includes an option for EDF to sell us their stake in CENG in the future. The financial structure of the agreement allows Exelon to take over day-to-day operations of the plants. It is intended to be as close to financially neutral as possible for the owner companies, enabling each to capture the value created by a world-class operator like Exelon operating the plants. We expect to close on the agreement in the first quarter or early in the second quarter of next year.

As a reminder, the appendix includes several schedules that will help you in your modeling efforts. Now I'll turn the call back to Chris for his concluding remarks before we open the call for Q&A.

Thanks Jack and Ken. Exelon continues to excel at our core competencies, operating our plants while keeping the lights on at the utilities and managing risk and optimizing our portfolio. We continue making productivity and operational enhancements to drive efficiencies across our business. Our strong balance sheet allows us to invest in our business and find ways to grow.

When we screen growth opportunities we look for value creating investments that are EPS, free cash flow and credit metrics accretive. We will act on those accretive opportunities at both an incremental level and a transformational level leveraging our skill and markets. Our operating agreement with CENG is a good example as Jack has just outlined. We are investing $16 billion in our business over the planning period, mostly in our regulated utilities, as Jack stated will result in a rate base growth of 5% to 6%.

In conclusion, we face a number of challenges. Exelon is focused on the fundamentals of our business throughout the growth process as we continue to add value to our shareholders. And with that, Ravi, I guess we will open up to questions.

Operator, we will now take questions from the participants. Operator?

(Operator Instructions). Stephen Byrd, Morgan Stanley.

I wondered if you could talk in a little more depth about the synergy potential with the additional nuclear units that you will be operating. Can you just talk in a little more specifics about what kind of operational advantages you see from this transaction?

The first advantage is a reduction of $50 million to $70 million of expense within the current operating model. And that is significant in itself. Beyond that is the flexibility to move resources around to continue to improve the talent development not only within our own fleet but the CENG fleet. We are really focused, as everybody knows, on the long-term viability of the small assets and we think this will give us a much better chance to have the whole fleet operate at a higher safety and reliability while reducing cost.

Great, thank you very much. And then shifting over to your wind business and thinking about some of your contracted assets, can you talk just generally about your appetite for either growing in that business or going the other direction and trying to monetize given the value of the contracted assets? How do you all think about the strategic path there?

So, Stephen, it's Jack Thayer. As we look at assets, and it's not just our wind assets, we look at what we believe the internal value of those assets are and then we bench that relative to what we see in the markets as an implied value for those assets. As you think about those wind assets, one of the opportunities that were working through right now is a project financing on our wind facility. And that we expect to raise somewhere between $625 million to $700 million of off-balance-sheet debt.

To the extent that we successfully complete that and we anticipate that in September of this year we will be -- then be in a position to look at those assets on an off-balance-sheet basis and see what is the optimal way to organize those within the Company. We also expect to use this off-balance-sheet structure to be able to the extent we are adding to our wind portfolio or our solar portfolio to optimize their capital structure to gain as much earnings accretion from those investments as possible.

The only thing I would add, we have continued to grow in the renewable space with, as Jack said, the wind and solar. But a long-term large-scale business model on a highly subsidized product is something that we watch closely. We have clearly stated that we think that Washington picking winners and losers on subsidies is not a long-term plan. So we will continue to monitor the federal policy and the state policy as we look at growth potentials in that area.

Great, thank you very much.

Greg Gordon, ISI Group.

When you talk about hedging through the gas markets, trying to leave your heat rate position open, how should we think about the way you are hedging in the context of, for instance, natural gas basis and PJM having collapsed relative to historical basis versus Henry Hub given the Marcellus situation?

I will get Joe to answer that, Joe Nigro.

Good morning, Greg. Greg, in our disclosure we show you our hedge percentages by region and you can see if we use 2015 as a proxy year, we are approximately 50% hedged which is right on ratable in the mid-Atlantic region and in the Midwest we are about 40% approximately hedged which would be 10% behind. As we have stated, we see the most amount of upside aligning to the Midwest region with all the changes that Ken talked about in his script.

The big thing, as it relates to gas hedging, is the bulk of the trade that we have done in gas is relative to our Midwest position. And the gas basis there has been much more stable. As you know, the mid-Atlantic basin has really seen a roll down with the Marcellus Shale. When you look at the gas basis at Citygate in Chicago over the last year or so the degradation has been much, much less than what it has been in the mid-Atlantic so the trade aligns well with our Midwest position.

Okay so you tend to trade the more liquid contracts at the Henry hub, so we should look at basis as being something that you have to manage if the basis starts to become more volatile?

Absolutely. And as you know, as you move out on the basis -- on the curve in time it gets more difficult to effectively execute the basis in different areas. We do use primarily the NYMEX contract and if there is an opportunity we will layer in the basis as appropriate.

Okay. A couple questions for Jack. You had laid out some numbers in terms of what you thought you would generate in terms of we investable capital over the next several years after the dividend cut and that that was sort of your sort of warchest for opportunities should they arise in the business. Can you reiterate what those numbers were and have they dissipated significantly because of the downturn in the retail and wholesale power markets on the capacity outcome?

Sure. So as you recall, we spoke to roughly $2 billion to $3 billion of balance sheet capacity on the first quarter call. With the degradation in power prices we have seen that come in. It is in a roughly $1 billion to $2 billion range now, and a way to think about this from a sensitivity standpoint is for every plus or minus dollar move per megawatt hour roughly to the plus side $750 million of capacity is created. To the downside roughly $650 million is lost depending on what power prices do.

Great. And Jack, where are you guys in terms of the evaluation of whether or not you're certain of your nuclear plants are viable in the longer-term and when might we get a decision on that?

Yes, this is Chris, I will cover that. We have worked hard over the last couple of years to continue to focus on cost to maintain some of the viability of the smaller units. As we have mentioned at our Clinton facility in MISO, the nuclear team has come up with a fairly good plan to put the plant on annual refueling cycles, which keeps it viable for years to come as the market recovers.

That is one of the newest boiling water reactors in our fleet and in the country. It's a well run plant that last year had a zero forced loss rate, so we are not ready to give up on it, we will continue to optimize its cost structure, maintaining it is safe but also neutral on the balance sheet.

As we look at our other smaller ones, being able to bring Ginna into the Exelon cost structure I think will give us time to continue to look at that as we understand the policies that are evolving in New York around capacity and transmission. So there is nothing on the chopping block right now. It is constant work to look at cost, it is constant work to look at regulatory structure and if it does not improve we will be talking more about those facilities.

Okay, my last question is -- I know it sounds maybe like an odd question, but one of the things that you did in the restructuring of the joint venture with the put option with EDF is indemnify them against a serious nuclear accident. I know it is a tail risk, but it seems like a very large risk to be saddling your shareholders and bondholders with. Can you explain the logic there?

We will get to Bill to --.

Greg, this is Bill Von Hoene. As you know the indemnification is for Price-Anderson exposure corresponding to their ownership interest in the plants. Each unit in the United States has an exposure to this and there are 104 units and I think the exposure for each is about $117.5 million potential retro call for a Price-Anderson event which is a catastrophic event.

And understanding what that means, TMI was not a Price-Anderson event. Price-Anderson has never been invoked. So what you have is on a plant-by-plant basis you have that exposure, it's limited on a per year basis to $17 million per plant. So essentially what happens here is in the event that there was a Price-Anderson event, which has never occurred, and there was a call and the call is pro rata in the plants and it was a call for the full amount the maximum exposure would be about $50 million a year.

So we -- looking at that, looking at what the collective insurance arrangement is and looking at what the events are that would be eligible for this we do not consider this to be material to the transaction.

Great, thank you guys.

Dan Eggers, Credit Suisse.

(Technical difficulty) savings or are you of kind of the idea of eliminating inflation at ExGen? Can you talk a little more (multiple speakers).

You sort of came in midstream there, do you mind restarting.

Yes, sorry, sorry. When you guys look at the O&M savings you are talking about at ExGen, both the cut this year and then sustain for the next couple years, can you give a little more detail on where those savings are coming from given the fact you guys are already pulling out so much money from the synergy benefits from the merger and the upsizing of that so far?

Yes, Dan, it is Ken, I can help with that. We are on the Constellation side continuing to look at vacant positions in attrition and sweeping them and not filling them as we evolve with our transformation in our organization from the Exelon and Constellation merger. So we have been very disciplined about not hiring until we realize the full efficiency of the merger and the capabilities of the organization. And you have got to keep that in the context of what we are facing in the commercial markets right now.

We had a plan that had retail growing at a more aggressive level, we backed that plan down, as you can see in the hedge disclosure, and we have backed our cost structure down accordingly. So we also have continued opportunities on the Constellation side while we finish our systems integration to improve processes, lower our costs on our IT systems. So I'm very comfortable with half of that $100 million I talked about coming from Constellation and even maybe some more.

On the GenCo side it is really been about non-labor opportunities. Our pension costs are down with interest rates going up, our insurance costs are a bit down and our ExGen CAGR was not very high to begin with before we rolled this extra $100 million out, we were around 0.5% already. So we think it is well within our capability to achieve a flat CAGR.

Does the CENG savings get put into that number, Ken, or is that coming in somewhere else?

The CENG savings will be on top of this.

So CENG savings are incremental to that number, okay.

That is correct.

And then I guess, Ken, just kind of on power market recovery and the $2 to $4 a megawatt hour which has kind of been the expectation for a while, heat rates did come back this quarter from where we had seen those, you've got a negative reset down. Did that mean that basically your outlook for power prices in general have also come down because you have kept that recovery number at the same level? Or should have that recovery number expanded based on your fundamental view of where the market would have been say a quarter ago?

Dan, one thing to realize is we don't want to be chasing this every time market prices go up and down. I would say $2 to $4 right now is conservative. And our views are that there is substantial upside probably on the high-end of that $2 to $4 or even more in the marketplace.

We have beaten our models up, we have gotten some new models to challenge ourselves, we have challenged ourselves with some outside help and everything I see indicates that this upside should be there in the markets fundamentally when the system actually dispatches.

When we are going to see it in the marketplace, we don't know. And we have to be prudent about how we manage the business accordingly. But we -- I see $2 to $4 being probably a conservative number right now if you are looking at current market prices.

Okay, I just -- for the overlay just for context, how much demand growth do you guys assume you see in your territories on a long run basis to support that level of power price recovery?

Do you want to --?

In the PJM territory, which is what we are really talking about with this upside, Dan, it is under 1%.

Under 1%, got it.

And (multiple speakers) some energy-efficient that discounts on top of that.

So 1% and then you net back efficiency so it is more like 0.5% or something?

Between 0.5% and 0.75% is probably a good assumption.

Okay, thank you, guys.

Jonathan Arnold, Deutsche Bank.

Dan asked most of what I was just about to ask, so I'm going to keep this short. Just to clarify one thing, on the $50 million to $70 million -- I apologize, I was on jumping between calls -- is that your -- the Exelon benefit from the shift or is that kind of a gross number in the entire JV of which your share is half?

It's a gross number.

Okay, so half of that is kind of what will accrue to you on top of the $100 million of other savings?

Yes.

Okay, great. Thank you.

Julien Smith, UBS.

So perhaps the first question and, again, following up on the last few here, just in terms of aggregate cost cuts, if you could kind of quantify here. Is it correct to take both the Exelon numbers and the half of the $50 million to $70 million from the CENG to get to kind of a total aggregate reduction in 2013 and beyond? And maybe the better question is, the $50 million to $70 million, when exactly do you start realizing that on a run rate basis?

So, that is accurate. To aggregate them we will start to make the adjustments in the organization and start to achieve the savings after we receive the regulatory approval, which is anticipated sometime around March 15 of next year, 2014. So the restructuring to garner the savings will happen in 2014 and the long-term run rate my anticipation would be 2015.

For the CENG portion specifically?

That is right.

Excellent. And moving back to the power side for a quick second. You talked about FTRs and congestion, what is being done to resolve that? I mean is that something that we should expect that should turn around next year or is that a potential liability for next year as well? I mean, how have you positioned that with respect to your guidance and from a regulatory perspective as well?

So, Julien, we have seen a run rate over history of receiving around 90% of our allocated ARR and FTR values. This year that has come down about 20% on us. It is due somewhat to the allocation process and how PJM models the system and allocates ARRs in initial stages of that process. It is also due to what I would call less than optimal seams, issues and dispatch between MISO and PJM that are causing congestion issues at the seams.

When you get substantial congestion issues in the market, PJM can't collect enough revenue on congestion to pay back the ARR and FTR holders. So it is -- it is a relatively new challenge for us; what we see is working with PJM and MISO to improve the seams issues is one of the first and foremost things we can do. We also see as the transmission system itself gets upgraded and starts to handle the capability of new supply that will help the situation as well. But prudently we have to plan for lower collection until we see those changes occur.

So you would say that is baked into the 2014 and 2015 expectations at this point?

Yes.

Okay, all right, great. And then with regards to PJM policy overall, just kind of lastly here, obviously a lot a focus on transmission imports. Is the goal at PJM really to kind of tackle transmission and sort of how that is done? Or is it more to tackle buying back and sort of that whole element of arbitrage, if you will?

Julien, this is Joe Dominguez. I think it is probably more the latter. I think eliminating the incentive to arbitrage between a base residual auction and the incremental auctions is the direction the stakeholder group is looking at. I think we are also looking at some of the deficiency penalties that determine whether they are sufficient, likewise credit and look at the milestones that need to be accomplished for all planned resources.

PJM and IMM may have some other proposals that will come into this, they have started talking about that. That may go into direction of limiting imports, but it is early to tell.

All right, great. Thank you.

Ali, SunTrust.

First, I just wanted to clarify -- I know when you were talking about the cost savings it seemed to me that some of the savings for 2013 may be more 2013 specific -- lower depreciation and what have you. But just to be clear, as I look forward should we assume that relative to the margin erosion that you are seeing in 2014 and 2015 on the latest forward curve, that about $140 million or so of that is being offset from cost savings? Or how should we think about that on the 2014-2015 outlook if I am hearing you right?

The complete long-run cost savings that we talked about should be achieved by the first of 2015, which includes the CENG cost savings along with the GenCo cost savings. You want to talk about your trajectory of your --?

The $100 million, Ali, will be in 2013, 2014 and 2015. So achievable now and held for that period.

Understood. And then secondly, Chris, do you again hearing you guys -- I mean the $2 to $4 uplift, you have talked about that versus fundamentals, versus market. Let's say that does not materialize, hasn't materialized today. Should we assume Exelon will continue to focus on costs, perhaps a hunker down strategy, wait for that turn to happen?

Or I mean, strategically do you step back and say, maybe there is something else that I need to do. Maybe my portfolio mix is not right at the market, it's just not there. How should we be tracking that from your perspective?

Sure. On one side we will continue to aggressively focus on the safety and reliability on our utility side, which allows us to continue the opportunity to make significant investments over the planning period. So you can see a real focus on the utilities over the next five years putting $13 billion to work and continuing to grow the rate base at 5% to 6%.

On the generating side we are definitely within the 2013-2014 year time frame in the hunker down mode, watch all expenses, maintain the assets, which we think we have a competitive advantage on our asset mix, and watch for the market to come back. And we think, as all of you, we are the best levered for a market recovery.

On an annual basis we always go back in the fall and say, what if we get it wrong? What are our paths forward? What is our strategic planning? We will do that again this year, like we do every other year. We'll look at our fundamental modeling, we will look at external sources of fundamental modeling and we will look at alternatives.

But right now we feel that the -- what we've talked about on a market recovery is -- should happen within the timeframe on the power side even with the disappointment of the capacity market on the 2016 and 2017 side we see that power upside coming back.

On the capacity side, like we said, it is disappointing but not devastating. But that is one data point, we will have to continue to work in the stakeholder process to fix this issue and look for any others. But if we continue to see issues with the capacity market we would only -- it would be prudent for us to go back and make sure that we are looking at the strategic mix and how we are structured. We believe in it, we believe in the competitive market, we are wed to it, but we will always continue to reevaluate it.

Great, and last question, Chris, you're still comfortable also with the dividend -- the new dividend level even if that $2 to $4 is not materializing?

Yes, definitely. If you go back to some of our earlier calls on this and Jack has reiterated that, the dividend is essentially sized for the regulatory business to handle with a 65% to 70% dividend up to the Holdco. So we could maintain what we think is a very competitive dividend within Exelon or paying to the Exelon shareholders while we are able to use the balance sheet of the competitive business to grow and feed that -- those dollars of free cash flow back into the competitive business.

Thank you very much.

Paul Fremont, Jefferies.

A couple of clarifying questions. When you talk about the 0% compound annual growth in O&M through 2015, I assume that does include the CENG savings that you have identified or is CENG incremental to that?

No, it is incremental to that.

It is incremental, okay. Second clarifying question is, I think you affirmed the $2 to $4 guidance for retail supply margin, but you talked about margin pressure on the wholesale side as previously I think you had provided a range of $1.50 to $3 per megawatt hour on wholesale. What would that number -- has that number been revised?

We haven't revised the wholesale number, Paul, I did reaffirm in my comments the $2 to $4 on the retail side albeit we're expecting to be at the low end of that range. On the wholesale side, as you can see in the volume chart we provided you, that we are reducing the percentage of wholesale load that is in our projections relative to retail. So we are still seeing that $1.50 to $3 opportunity, albeit the volumes are a little lower than we expected.

Okay. So the -- but the margin, we should assume similar margins then is what you've provided in the past?

Yes, lower end of the range on the retail side right now though is what you should assume.

Okay. And then in terms of the $50 million reduction that you are looking to achieve at Constellation, is that linked to the lower volumes or is that -- or should we assume that that represents a reduction in the fixed cost in the business?

It is some of both, Paul. First, we did have a plan that has us growing our retail business, which meant growing on the labor side. And to the extent we are not growing we can maintain current labor position, that is a reduction of our plan. We've also been very disciplined while we are integrating the Exelon and Constellation commercial platforms and we continue to do that on the IT side.

While we are doing that we been very disciplined about not finalizing our design and hiring open positions in the business until we get our efficiencies, our systems and our processes all where we want them to be. So again, I am very comfortable that Constellation can achieve that cost challenge.

So with both is it more skewed towards variable or evenly skewed?

I would say it's more skewed toward fixed and, to the extent there is some variable because of our situation and our lack of growth in that business, there is some benefit there as well.

And then with respect to EDF, are you basically obligated under that put option to buy them out? And who basically ends up doing the market assessment and that calculation?

Paul, this is Bill Von Hoene. The put option obligates us to buy them out under a process that protects us -- we believe very carefully protects us in terms of having an accurate market value. Essentially the process calls for each side to designate an investment bank to determine the fair market value and this is the fair market value of the EDF share. So if this happened before we repay the dividend or repay the loan that is net of that.

They then try to agree on a price. If they are unable to agree on a price there is a third party that is designated by the two investment banks and that party would determine a price and it would be a baseball arbitration type of arrangement. There is also built into it flexibility to accommodate other business needs that we may have during the period of time it might be called.

Operator, we will take one last question now.

Neil Mehta.

(Technical difficulty) Lapides at Goldman here. Real quick -- actually two separate ones. One, gas generation, we are seeing lots of new build announcements in PJM these days. Just curious if you think they are economic or not and any worry about a wave of new combined cycles coming into PJM especially with gas basis and the Marcellus now upside down a little bit?

The second one is, can you give an update on the MATS litigation that is outstanding? I don't know if a lot of folks are following this, but that case is actually sitting at the DC circuit waiting on judges to be assigned, and just curious your views about the risk around that litigation?

Let me cover the new build first. Lots of announcements, I don't know if I would agree -- but there have been announcements on some CCGTs in PJM, the earlier announcements were subsidized, they had to be subsidized based off of the economics, I think they have all had their struggles to some extent on being built. There are others that are going to build at risk, I think it is less than a handful that I can point to right now that are doing that.

We continue to evaluate their economics, even with the stated cost per kilowatt number, a $60 megawatt day clearing price does not cover the economics for us. So as some of the later -- the newer announcements saying they could build for under $500 at KW, we don't think it includes owners' cost, it is not with an EPC agreed-upon and the economics -- we can't get the economics even on a brownfield side to get there.

So we continue to watch that and we will keep our eyes on it. But from the way we are modeling it we don't see it work. Now that could be first movers anticipating something in the fundamental models that we don't see like a more significant growth rate, greater load growth rate, greater reduction on installed capacity, some kind of new behavior on bidding on RPM, but from our modeling we don't see it. The second part I will ask Darryl Bradford to discuss on the MATS.

As you suggest, the MATS litigation is fully briefed, it is waiting for oral argument in the DC circuit. We expect that to be scheduled sometime in the fall. And while there is always risk in litigation we've carefully reviewed all of the briefs and arguments and we think that the EPA's argument is very sound and that the court should sustain it. We will get a better read on what the court's reaction is to those arguments when the oral argument is held. But we do think the EPA rules should be upheld by the DC circuit.

Got it. Thank you, guys, much appreciated.

Okay, operator, that should conclude the call.

Thank you, ladies and gentlemen, that does conclude today's conference call. You may now disconnect your lines.