Ravi Ganti – Vice President of Investor Relations Christopher M. Crane – President and Chief Executive Officer Jonathan W. Thayer – Executive Vice President and Chief Financial Officer Kenneth W. Cornew – Executive Vice President and Chief Commercial Officer Joseph Dominguez – Senior Vice President, Governmental and Regulatory Affairs & Public Policy William A. Von Hoene, Jr. – Senior Executive Vice President and Chief Strategy Officer Darryl Bradford – Senior Vice President and General Counsel

Stephen C. Byrd – Morgan Stanley Greg Gordon – ISI Group Daniel Eggers – Credit Suisse Jonathan Arnold – Deutsche Bank Securities Inc. Julian Smith – UBS Ali Agha – SunTrust Robinson Humphrey Paul Fremont – Jefferies & Company Michael Lapides – Goldman Sachs

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 our 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 maters 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 Exelon’s other filings for a discussion of 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. Christopher M. Crane: Good morning and thank you for everybody joining. We delivered on our financial and operational expectations this quarter. In the markets lower commodity prices continue to challenge us both in the near-term in 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’ve 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’re 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 remained 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 and cost and strong utility performance. And both Jack and Ken will provide more details around that. Moving to operational excellence on Slide 1, we’re on track for very good year operationally. Our Generation fleet performed well of this quarter, nuclear ran at 92.8 capacity factor in the second quarter despite our refueling outage days which is normal and for the loss of offsite 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 State Bill 9 was enacted this quarter. It enables us to start executing grid modernization plans, including installation of Smart Meters to improve reliability. We’ve filed rate cases of 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 and PJM, we’re 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. 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 expected by year end. And ComEd Smart Meter deployment begins in September with 60,000 meters expected by year end and we’ll 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 a 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 the 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 have 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’ll turn it over to Ken Cornew to provide some more specifics on power and gas markets in our retail business. Kenneth W. Cornew: Thanks Chris and good morning everyone. As Chris mentioned I’ll cover 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. 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 continuous 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 PJM supply stack that have occurred over the last few auctions. As you can see from this 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 and the 2016, 2017 planning year imports, demand response, 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 continued 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 it in our current forecast. Additionally, the retired coal units are being replaced by some supplier resources which have a very different dispatch profile. This can lead to increased volatility in spot energy prices. We have many issues to consider from this RPM auction. Will the require transmission for imports to 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 isses of the 2015, 2016 auction, 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 4 provides an overview of how we position 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 NI Hub decreased by $2.90 a megawatt hour and $2.68 a megawatt hour in 2015 respectively. Natural gas prices decreased approximately $0.16 an Mmbtu 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 loan growth assumption. We have acted on this view and have widened our deviation in rateable across our entire portfolio in the past six months, which has reached approximately 8% under-rateable for 2015. The actual deviation in a pure underlying power position is even greater, when auctions and cross 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 in 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 positions 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 competitions 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 day for portions of our AVSR solar project. Despite these delays there’ll 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 rates or FTRs otherwise known as congested rates. For those of you that monitor PJM you likely know this under collection situation for entities that only these congestion rates are being paid significantly less than their full value. Third the remaining is due to $50 million reduction in our new business targets for the year largely attributed to reduced expectations at our wholesale gross margins. 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 on our under hedged 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 in 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’re still optimistic that we can grow the retail business, but given the overall competitive environment, we have seen over the last 18 months, we’ve chosen to be more conservative in our volume estimates. To mitigate the impact of lower gross margins and new business targets, we continue to take a hard look at our cost and optimizing our process. We’ve reduced the Constellation O&M budget by roughly $15 million for 2013, 2014 and 2015. We’ll continue to look for additional opportunities to further reduce our operating costs for process and system improvements. In total, ExGen’s reducing its Q&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’ll now turn it over to Jack, to review the full financial information for the quarter. Jonathan W. Thayer: Thank you, Ken and good morning everyone. I’ll 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’ll 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 a favorable 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 appreciation offsets due to the AVSR delay. We will continue to look 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 rev 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 in the prior period last year. This is primarily driven by the reversal of the write-down of a regulatory asset we recorded in Q2 of 2012, based on 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 earnings in the prior period last year. This is related to the increased electric and gas rates that were received in the 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 overwrote 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 request reflects actual 2012 expenses and investments and forecasted 2013 capital additions through our distribution network. We expect the decision by year end with a new rates going into effect in January of 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’re 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 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’ve 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 and 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 to 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 I 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’ve upsized our planned ComEd long-term debt issuance by $500 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, 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 in 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 refinancing flexibility to Exelon as new banking regulations are implemented over the next several years. Yesterday, we announced that we 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 next year. And 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. Christopher M. Crane: Thanks to 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 in 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 we’ll result in a rate based growth of 5% to 6%. In conclusion, we faced 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’ll open up for questions.

Yes, sir. Operator, we’ll now take questions from the participants.

(Operator Instructions) Your first question comes from the line of Stephen Byrd of Morgan Stanley. Stephen C. Byrd – Morgan Stanley: Good morning. Christopher M. Crane: Good morning, Stephen. Stephen C. 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’ll be operating. Can you just talk in little more specifics about what kind of operational advantages you see from this transaction? Christopher M. Crane: The first advantage is a reduction of $50 million to $70 million of expense at the current within the current operating model and that’s 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’re 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. Stephen C. Byrd – Morgan Stanley: 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? Christopher M. Crane: Go ahead Jack. Jonathan W. Thayer: Sure. 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 market as an implied value for those assets. As you think about those wind assets, one of the opportunities that we’re working through right now is our project financing on our wind facility and that we expect to raise, somewhere between $625 million to $700 million of balance sheet debt. To the extent that we successfully complete that and we anticipate that in September of this year, we’ll then be in a position to look at those assets on an off balance sheet basis and see what’s 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’re 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. Christopher M. Crane: The only thing I would add, we have continued to grow in the renewable space 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. 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, it 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.

Your next question comes from the line of Greg Gordon of ISI Group. Christopher M. Crane: Hey Greg. Greg Gordon – ISI Group: When you talk about hedging through the gas markets, just 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? Christopher M. Crane: I’ll 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 the script. The big thing is as it relates to gap 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 basis has really seen a roll-down with the Marcellus shale, when you look at gas basis at city gate in Chicago over the last year or so, the degradation has been much, much less than what it's been in the Mid-Atlantic. So the trade aligns well with our Midwest position. Greg Gordon – ISI Group: 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, 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 then if there is an opportunity we will layer in the basis as appropriate. Greg Gordon – ISI Group: 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? Jonathan W. Thayer: Sure. So, as you recall, we spoke to roughly $2 billion to $3 billion of balance sheet capacity in the first quarter call, with the degradation in power prices, we have seen that come in. It’s 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 from megawatt hour roughly to the plus side, $750 million of capacity is created to the down side roughly $650 million is lost depending on what power prices do. Greg Gordon – ISI Group: 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? Christopher M. Crane: 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 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. As one of the newest boiling water reactors, in our fleet and in the country, it’s a well-run plant, which last year had zero-force loss rate and so we are not ready to give up on it, we are continuing to optimize its cost structure, maintaining it safe but also neutral on the balance sheet. As we look at our other smaller ones, being able to bring Gannett into the Exelon cost structure, I think will give us time to continue to look at that, as we understand the policies that are revolving 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's constant work to look at regulatory structure and if it does not improve, we will be talking more about those facilities. Greg Gordon – ISI Group: 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? Christopher M. Crane: Bill you want to go ahead? Jonathan W. Thayer: Yeah, we will get Bill to… William A. Von Hoene: Yeah. 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. There are 104 units and I think the exposed rate 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 ever been in both. 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 there was a call for the full amount. The maximum exposure would be about $50 million a year. So 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. Greg Gordon – ISI Group: Great, thank you guys.

Your next question comes from the line of Dan Eggers of Credit Suisse. Daniel Eggers – Credit Suisse: Savings are your kind of the idea of eliminating inflation at ExGen, can you talk a little more… Christopher M. Crane: Dan. Daniel Eggers – Credit Suisse: Yeah. Can you hear me, sorry. Christopher M. Crane: You sort of came in midstream there do you mind restarting? Daniel Eggers – Credit Suisse: Yeah, sorry, sorry. So 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, could 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? Kenneth W. Cornew: Yeah Dan its Ken, I can help with that. We are on the Constellation side continuing to look at vacant positions and attrition and sweeping them and not [fill in] 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 realized the full efficiency of the merger and the capabilities of the organization and you 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 had back that plan down as you could see in the hedge disclosure, and we backed our cost structure down accordingly. So, we also have continued opportunities on the Constellation side and while we finish our systems integration to improve processes, lower our cost on our IT systems. So, I'm very comfortable with half of that $100 million I talked coming from Constellation and even maybe some more. On the Genco side, it's really been about non-labor opportunities. Our pension cost 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 are around 0.5% already. So, we think it’s well within our capability to achieve that flat CAGR. Daniel Eggers – Credit Suisse: Does the CENG savings get put into that number, Ken, or is that coming in somewhere else? Christopher M. Crane: The CENG savings will be on top of this. Daniel Eggers – Credit Suisse: So CENG savings are incremental to that number, okay. Kenneth W. Cornew: That’s right. Christopher M. Crane: That’s correct. Daniel Eggers – Credit Suisse: 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 have 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? Kenneth W. Cornew: Dan, one thing to realize is we don’t want to be chasing as 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 I see, $2 to $4 being probably a conservative number right now, if you are looking at current market prices. Daniel Eggers – Credit Suisse: 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? Kenneth W. Cornew: Its under – in the PJM territory, which is what we are really talking about, with this upside Dan, it’s under 1%. Daniel Eggers – Credit Suisse: Under 1%, okay got it. Kenneth W. Cornew: And then we have some energy efficiency discounts on top of that. Daniel Eggers – Credit Suisse: So, 1%, then you net back efficiency, so it’s more like 0.5% or something? Kenneth W. Cornew: Between 0.5% and 0.75% is probably a good assumption. Daniel Eggers – Credit Suisse: Okay, thank you guys.

Your next question comes from the line of Jonathan Arnold of Deutsche Bank. Jonathan Arnold – Deutsche Bank: Hello. Christopher M. Crane: Hey Jonathan. Jonathan Arnold – Deutsche Bank: Yeah I think 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? Jonathan W. Thayer: It’s a gross number. Jonathan Arnold – Deutsche Bank Okay, so half of that is kind of what will accrue to you on top of the $100 million of other savings? Jonathan W. Thayer: Yes. Jonathan W. Thayer: Okay, great. Thank you.

Your next question comes from the line of Julien Smith of UBS. Julien Dumoulin-Smith – UBS: Can you hear me? Jonathan W. Thayer: Yeah, we can hear you Julien. Julien Dumoulin-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? Christopher M. Crane: So that is accurate to aggregate them. We will start to make the adjustments in the organization and achieve, start to achieve the savings after we receive the regulatory approval which is anticipated sometime around March 15th of next year 2014. So the restructuring to garner the savings will happen in 2014 in the long term run rate my anticipation would be 2015. Julien Dumoulin-Smith – UBS: For the CENG portion specifically. Christopher M. Crane: That’s correct. Julien Dumoulin-Smith – UBS: 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? Christopher M. Crane: So, Julien we have seen a run rate over history of receiving around 90% of our allocated ARR and FTR value. So this year that’s come down about 20% on us. It’s due somewhat to the allocation process and how PJM models the system and allocates ARRs in initial stages of that process. It’s 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 and you get substantial congestion issues in the market, PJM can’t collect enough revenue on congestion to payback the ARR and FTR holders. So, it is a relatively new challenge for us. What we see is working with PJM and MISO to improve the seams issues as 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. Julien Dumoulin-Smith – UBS: So you would say that is baked into the 2014 and 2015 expectations at this point? Christopher M. Crane: Yes. Julien Dumoulin-Smith – UBS: Okay, all right, great. And then with regards to PJM policy overall, just kind of lastly here, obviously a lot of focus on transmission imports. Is the goal at PJM really to kind of tackle transmission and sort of how that’s 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’s probably more the latter, I think eliminate the incentive to arbitrage between the base residual option and the incremental options direction to stakeholder group is working at. I think we’re also looking at some of the deficiency penalties that determine whether there is sufficient pipelines 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've started talking about that they may go into direction limiting imports but it’s early to tell. Julien Dumoulin-Smith – UBS: All right. Great, thank you.

Your next question comes from the line of Ali of SunTrust. Christopher M. Crane: Good morning Ali Ali Agha – SunTrust Robinson Humphrey: Can you hear me? Christopher M. Crane: Yeah we can hear you. Ali Agha – SunTrust Robinson Humphrey: 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’re 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’m hearing you right? Christopher M. Crane: It’s 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. If you want to talk about trajectory… Kenneth W. Cornew: The $100 million Ali will be in 2013, 2014 and 2015, so achievable now and held for that period. Ali Agha – SunTrust Robinson Humphrey: Got it. Understood. Then secondly, Chris to you, again, hitting you guys, I mean the $2 to $4 uplift, you've 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 cost, perhaps a Hunker Down strategy, wait for that 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, and the market is just not there. How should we be tracking that from your perspective? Christopher M. Crane: Sure, on one side, we will continue to aggressively focus on the safety and reliability on our utilities 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 timeframe in a 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 were the best leverage 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's our strategic planning we'll do that again this year, like we do every other year, we'll look at our fundamental modeling, we'll look at external sources of fundamental modeling and we'll look at alternatives, but right now we feel that what we've talked about on a market recovery should happen within the timeframe on the power side. Even with the disappointment of the capacity market on the 16 and 17 side. We see that power upside coming back. On the capacity side, like we said it’s disappointing but not devastating. But that’s one data point, we'll 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, it would be prudent for us to go back and make sure that we’re looking at the strategic mix in how we’re structured. We believe in it, we believe in the competitive market. We are wed to it, but we will always continue to reevaluate it. Ali Agha – SunTrust Robinson Humphrey: A last question are you still comfortable also with the dividend, the new dividend level even if that $2 to $4 is not materializing? Christopher M. Crane: Yeah, 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 the 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’re able to use the balance sheet of the competitive business to grow and see that those dollars and free cash flow back into the competitive business. Ali Agha – SunTrust Robinson Humphrey: Thank you very much.

Your next question comes from the line of Paul Fremont of Jefferies. Christopher M. Crane: Hey Paul. Paul Fremont – Jefferies & Company: 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’ve identified or is CENG incremental to that? Christopher M. Crane: No, No Paul, it’s incremental to that. Paul Fremont – Jefferies & Company: It is incremental okay, second clarifying question is I think you affirm the 2% to 4% guidance for retail supply margin, but you talked about margin pressure on the wholesale side, previously I think you provided a range of a $1.50 to $3 per megawatt hour on wholesale. What would that number has that number been revised? Christopher M. Crane: We hadn’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 in the low end of that range. On the wholesale side as you can see in the volume chart, we provided you that we’re reducing the percentage of wholesale load that’s in our projections relative to retail. So we’re still seeing that $1.50 to $3 opportunity albeit the volumes are little lower than we expected. Paul Fremont – Jefferies & Company: Okay. So but the margin – we should assume similar margins than as what you provided in the past? Jonathan W. Thayer: Yes lower end of the range on the retail side right now though is what you should assume? Paul Fremont – Jefferies & Company: Okay. And then in terms of the $50 million reduction, that you're 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? Christopher M. Crane: It's some of both Paul. The first, we did have a plan that had us growing our retail business, which meant growing in on the labor side and to the extent we're not growing, we can maintain current labor position, that is a reduction of our plan. We have 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're doing that we've 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'm very comfortable that Constellation can achieve that cost channel. Paul Fremont – Jefferies & Company: So, with both, is it more skewed towards variable or evenly skewed? Christopher M. Crane: I would say it's more skewed towards 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. Paul Fremont – Jefferies & Company: 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 in that calculation. William A. Von Hoene: 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 that's embedded to determine the fair market value and that is the fair market value of the EDF share. So, if this happens before we repay the dividend or repay the loan, that's net of that. They then try to agree on a price, if they're 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 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.

We will take one last question now. Go ahead.

Your next question will come from the line of Neil Mehta. Christopher M. Crane: Hi Neil. Michael Lapides – Goldman Sachs: Lapides from Goldman here. Real quick. Actually, two separate ones. One, gas generation, we're seeing lots of new build announcements in PJM these days, just curious if you think they're economic or not and are you worried about a wave of new combined cycles coming into PJM especially with gas basis and the Marcellus now upside down a little bit? 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? Christopher M. Crane: Let me cover the new build, first. We made lots of announcements, I don’t know if I would agree with there have been announcements on some CCJTs in PJM. Your earlier announcements were subsidized they had to be subsidized based off of the economics. I think they’ve all had their struggles to some extent on being built. There is others that are going to build that risk, I think it's less than a handful that I can point to right now, they’re doing that. We continue to evaluate their economics even with the stated cost per kilowatt number of $60 megawatt day clearing price does not cover the economics for us. So, at some of the latter – some of the newer announcements saying they could build for under 500 a KW, we don’t think it's includes owner’s cost, it’s not with an EPC agreed upon and the economics, we can't get the economics even on a Brownfield site just to get there. So, we continue to watch that and we’ll keep our eyes on it. But from the way, we’re modeling it, we don’t see it work. Now they could be first movers anticipating something in the fundamental models that we don’t see like a more significant growth rate greater or low 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. Second part I'll ask Daryl Bradford to discuss on the MATS?

As you suggest the MATS litigation is fully briefed. It’s 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 carefully reviewed all the briefs and arguments and we think that the EPAs argument is very sound and court should sustain it. We'll get better read on what the court's reaction is to those arguments when oral arguments are held. But we do think the EPA rule should be upheld by the DC circuit. Michael Lapides – Goldman Sachs: Got it. Thank you guys. Much appreciate it.

Okay, operator that should conclude the call.

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