Ravi Ganti – Vice President-Investor Relations Christopher M. Crane – President and Chief Executive Officer Jonathan W. Thayer – Executive Vice President and Chief Financial Officer Joseph Nigro – Executive Vice President and Chief Executive Officer-Constellation Joseph Dominguez – Senior Vice President-Governmental and Regulatory Affairs and Public Policy Thomas D. Terry Jr. - Vice President- Tax

Dan L. Eggers – Credit Suisse Securities, LLC Steven I. Fleishman – Wolfe Research, LLC Jonathan P. Arnold – Deutsche Bank Securities, Inc. Hugh Wynne – Sanford C. Bernstein & Co., LLC Michael Weinstein – UBS Securities LLC Ali Agha – SunTrust Robinson Humphrey Jon A. Cohen – International Strategy & Investment Group LLC Paul B. Fremont – Jefferies LLC Michael J. Lapides – Goldman Sachs & Co.

Good morning. My name is Amy and I will be your conference operator today. At this time, I would like to welcome everyone to the Q4 2013 Earnings 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. Ravi Ganti, Vice President of Investor Relations, please go ahead.

Thank you, Amy. Good morning everyone and thanks for joining our fourth quarter and full year 2013 earnings conference call. Leading the call today are Chris Crane, Exelon’s President and CEO and Jack Thayer, Exelon's Executive Vice President and Chief Financial Officer. They are joined by other members of Exelon's senior management team, who will be available to answer your questions following the prepared remarks. We issued our earnings review this morning along with the presentation, each of which can be found in the Investor Relations section of our website. The earnings release and other matters that we will discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today’s call obviously during this call and the risk factors section of the earnings release. Please refer to today's 8-K and Exelon's other filings for a discussion of factors that may cause the results to differ from management's projections, forecasts, and expectations. Today’s presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the appendix of our presentation and our earnings release for reconciliation of non-GAAP measures to the nearest equivalent GAAP measures. We have scheduled 60 minutes for this call. I'll now turn the call over to Chris. Christopher M. Crane: Thank you Ravi, and good morning to everybody. Before I talk about 2013, I will give everybody a little bit of update on the system status. This year, this winter have provided us with a lot of opportunities to perform storm recovery in the last 36 hours, we’re hit pretty hard with snow in the ComEd zone. The recovery went fairly well, in fact we’re back up and running at normal levels. BGE was hit by freezing rain and ice yesterday morning knocking out Exelon PECO 175,000 customers. As of early this morning, there were 45,000 customers left to recover. We have adequate resources on the system now. PECO was the one that was most slanted by any of the utilities by this storm. Over 700,000 customers have been affected thus far making it the second worse storm in PECO’s history, only beat out by super storm Sandy. We had yesterday 35,000 resources on the ground in the recovery phase and that is ramping up even more today. ComEd is dispatching over 300 of their resources and will continue to support the recovery. As of this morning, there were still approximately 430,000 customers; out of that we expect to make some solid results in the next couple of days. This could last for few more days and we are really focused on this health and safety of our customers with another storm coming in, so company is doing everything possible to expedite the recovery there. So I’ll switch now to 2013; it was a strong year for operations. Each utility; PECO, BGE and ComEd achieved top quartile and best ever our outage frequency in customer satisfaction numbers. Nuclear delivered a capacity factor of 94% and an all-time higher generation output. Gas and hydro availability upon demand was over 99%, and renewable energy capture was 93%. We have been confronted by low power and gas prices, impacts of subsidized generation in sluggish low growth. With that said, we delivered on our financial plan. We achieved $2.50 a share which was right in line with our guidance and Jack will be providing more color on that in a minute. We continue to manage cost O&M was better than planned, realizing $360 million in merger synergies and on track to 550 ComEd's by year-end. Previous actions have ensured solid credit metrics and balance sheet strength that allows us to continue investing and growth. You know about the $15 billion in utility investment we’ve talked of. Jack is going to provide more color on that also in a minute. We had more than $1.3 million smart leaders during 2013 end to other infrastructure upgrades and system hardening and transmission projects. We added 158 megawatts of clean generation primarily at our Antelope Valley solar facility and we have the substantial generation growth in our development pipeline for the next two to three years, approximately 500 megawatts and contracted win solar in the completion of our nuclear power upgrades. Public policy remains a critical focus for us. At the utilities, we saw meaningful improvement in the fair return on our investments in Illinois and Maryland, Senate Bill 9 in Illinois allowed us to achieve our grid modernization programs, which is driving customer liability and we are having constructive result on rate cases in Illinois and in Maryland. It is clear that Exelon and other competitive generators are not really compensative for their reliable generation. We’ve been active in the PJM stakeholder process since we auctioned results of last May to improve the rules. We continue to be a leading voice against subsidized generation and have had some success. We will continue the efficacy process going forward. Looking-forward, we see some challenges, but we hope to do see some light at the end. Continued pressure from subsidies and lower commodity prices are present, but the recent weather events have resulted in price volatility that we haven’t seen in a long time. This should result in supplier side risk premium adjustments, which will assist in the market recovery and we have given this and other fundamental shifts we remain positive. Today, we are providing guidance range of $2.25 a share to $2.55 a share for the adjusted period earnings for 2014 and now I’ll turn it over to Jack to provide more details. Jonathan W. Thayer: Thank you Chris and good morning everyone I am on Slide 2. I’ll first discuss the fourth quarter and 2013 financial results and then turn to 2014 earnings guidance cash outlet and other insights on 2014 including our gross margin update. We achieved operating earnings of $0.50 for the quarter and $2.50 per share for the year, in line with the midpoint of our guidance expectations of $2.40 to $2.60 Turning to Slide 3 in the quarter results for utilities; 2013 was bad year for our three utilities. Our utility customers are realizing the operating and cost benefits of the merger, each BGE, ComEd, and PECO had its best operating year ever, hence will approve for the value of scale and the ability to leverage experience, cost utility, best practices and resources. Operating performance in each utility improved over 2012 in all key metrics including safety, reliability, customer service and customer satisfaction. For all three, reliability customer satisfaction and add frequency are in the top quartile of similar utilities in the United States. We continue to make capital investments to make our system even stronger and more reliable. For the fourth quarter ComEd delivered earnings of $0.13 per share and full year earnings of $0.49 per share at the top of our guidance range. Fourth quarter earnings decreased to $0.06 per share compared to the same period of 2012, related to the impacts of the October 2012 distribution rate order, partially offset by favorable weather, volumes and customer mix. PECO delivered earnings of $0.12 per share for the quarter and $0.46 per share for the year, exceeding our guidance range. Fourth quarter earnings increased $0.02 per share over the same period last year; this is largely related to decrease storm cost and favorable weather. BGE's earnings were $0.06 per share for the fourth quarter and $0.23 per share for the full year, in the middle of our guidance range. Fourth quarter earnings increased by $0.04 per share from the same quarter in 2012. Higher electric and gas distribution rates and lower storm cost drove the higher earnings. In December, both ComEd and BGE received constructive results in their rate cases. The Illinois Commerce Commission approved to an increase of $341 million for commerce delivery service revenue, nearly 95% of the original request, a testament to the success of the formula rate mechanism. And the Maryland Public Service Commission approved an increase of $34 million for electric base rates. And $12 million for gas base rates. The 2014 outlook for lower growth remains modest. We expect less than 1% load growth in our PECO and BGE. And load growth to be flat to negative at ComEd. At each utility load growth is influenced by ongoing energy efficiency programs. PECO's modest growth of 0.3% reflects growth in manufacturing employment in the region. Strong growth in the residential sector is driving BGE’s 0.6% expected load growth in 2014. There is more detail on load for the utilities that can be found on page 27 of the appendix. Turning to ExGen’s results of Slide 4. ExGen delivered earnings of $0.21 per share in the fourth quarter, and $1.40 per share for the full year. For the quarter ExGen’s earnings decreased by $0.12 per share compared to the same quarter of 2012. The majority of the decrease was driven by lower realized energy prices across all regions. This was offset in part by higher capacity prices and lower O&M expense. : Slide 6 provides our projected sources and uses of cash for 2014 compared to 2013 actuals. Cash from operations is expected to be $6.1 billion which is an increase from 2013 or $75 million due in part to higher distribution rates at ComEd and favorable income taxes and other settlements offset by lower gross margin and Exelon generation. 2014 CapEx plans are largely consistent with our estimates provided at EEI. I will discuss our O&M outlook on the next slide, but would first touch upon our financing plans for 2014. We’re projecting $1.2 billion of long-term debt issuances at ComEd and PECO with the proceeds to be used for refinancings and incremental capital investment at ComEd. In early January, we completed more than half of our 2014 financing plan for the $650 million ComEd first mortgage bond issuance. The transaction consisted of $300 million of five year bonds with the coupon of 2.15% and $350 million of 30 year bonds with a coupon of 4.7%. The proceeds served to retire $617 million of debt maturities in addition to general corporate purposes. In addition to the maturity comment, we have $525 million of maturities at ExGen which we’ve retried with cash on hand improving our credit metrics as a non-regulated business. As mentioned on the third quarter call, we think we have an opportunity to redeploy capital for growth opportunities through project financing of certain assets in our existing portfolio. To that end, I’m pleased to announce the closing of a $300 million L plus 425 term loan of ExGen Renewables I. ExGen Renewables I is the indirect holding company of Continental Wind, a $667 megawatt wind portfolio of 13 projects located in six states, refinanced in September of last year, this transaction had an order book that was well over subscribed consisting of high-quality investors resulting in our springing and pricing by 25 basis points to 50 basis points from our initial guidance. We think this serves as evidence that we have a strong portfolio of assets that can generate additional proceeds to deploy for the right growth opportunities. Slide 7 shows our 2014 O&M forecasts and our 2013 actual O&M. We project O&M for 2014 to be $6.575 billion, an increase of $100 million over last year. The O&M CAGR for the entire company from 2014 to 2016 is a negative 0.6% with ExGen O&M remaining roughly flat during that time period. This year-over-year variance is mostly driven by inflation and the anticipation of average storm costs at the utilities offset by merger synergies and favorable pension and OPEB costs. We expect to hit our run rate merger synergy target of $550 million in 2014. On Slide 8 as we told, at EEI we are investing $15 billion in our free utilities over the planning period, resulting in consolidated rate base growth of between 5% and 7%. We are targeting a minimum 10% ROE at each utility by 2017. Our utilities provide stable earnings growth for the company and could wholly fund the dividend of 2016. We expect consolidated utility earnings will grow 6% annually from 2013 to 2016. Slide 8 shows our projected utility earnings range from $1.10 to $1.40 in 2014 from $1.25 to $1.55 in 2016. : : In January we experienced severe winter weather in our load shedding regions as well as significant power and gas price volatility. Our balanced generation to load strategy, as well as our geographic and commodity diversity, served us well in this challenging environment. : Yesterday, ISO New England announced the preliminary results of their full capacity option for the planning year of 2017 and 2018. The clearing prices are $15 per kilowatt month in NEMA and $7.025 per kilowatt month in the Rest of Pool. These results are pending for approval. The clearing prices reflect the tightening supply and demand balance in New England after to announcements to retire baseload generation. Our New England capacity position 2100 megawatt in NEMA and 735 megawatts in Rest of Pool will benefit from these higher year-over-year prices. As you will see in the appendix, our forecasted generation has decreased by roughly 50% in New England. Exelon worked with the supplier to restructure certain trends of a fuel supply contract resulting in a more flexible and a reliable supply contract. Despite the fact that our forecasted generation is lower, the changes in the fuel supply contract result in favorable gross margin variances in the portfolio that are included in the open gross margin forecasts. On Slide 10, we believe that PJM prices will improve due to full time retirements and increased costs for some generators to comply with impending environmental regulations. : Our hedging strategy continues to reflect this view. Our overall hedge percentages increased due to two factors; the restructuring of the New England fuel supply contract and shifting to a larger heat rate strategy of PJM. As of yearend 2013, we were 2% to 3% behind ratable in PJM relying on an even larger amount cross-commodity hedges to capture our view that heat rates will expand. At year end natural gas sales represented 12% to 15% of our hedges in 2015 and 2016. The changing fundamental drivers of the gas and power markets have already led to significant amount of volatility so far in 2014 spot prices. The power market have modestly responded. We will continue to evaluate the amount of upside we see in the market based on our fundamental views and carry positions that will allows us to benefit as much as possible from the realization of these use while meeting the other goals of our hedging policy. On Slide 11, ExGen have shown strong financial metrics and cash flows to maintain its investment grade rating and pursue opportunistic growth investments as they arise. For 2013, ExGen had an FFO to debt ratio of more than 37% and we expect this ratio to improve in 2014 to approximately 40%. ExGen’s investment grade, credit rating and robust balance sheet allows us to pursue growth projects. As we showed you at ETI, we have declining base CapEx of ExGen from 2013 to 2016. Our priority is the safety and reliability of these plans and these cost reductions will not compromise our ability to achieve those priorities. Our base CapEx in prior years was higher to prepare for license extensions and mitigate asset management issues. We are also able to implement cost management programs including reverse engineering, which contributed to reductions. These CapEx reductions helps to mitigate the reduction in rev net fuel. Pension improvements are also contributing to our strong financial strength when looking at cash relative to earnings. The rising interest rate environment results in lower pension costs and contributions. For 2015, we are forecasting a $100 million decline in pension contributions versus expense. Further ExGen has a favorable cash tax position. We have substantial near-term cash tax favorability compared to book taxes due to bonus depreciation, use of NOLs and other tax credits. Our longer term tax position has increased tax capacity for growth opportunities in renewable generation. All these factors contribute to our financial flexibility and robust cash metrics including EBITDA minus base CapEx of $1.5 billion to $1.8 billion and free cash flow of $1.25 billion in 2014. We have a financial strength not only to see us through this period of low commodity process, but also to grow. Our healthy balance sheet, sustainable dividend and our discipline constitute a solid platform for sustained growth. As a reminder, the appendix includes several schedules that will help you in your modeling efforts. Now I will turn the call back to Chris for his concluding remarks, before we open the call for question and answer. Christopher M. Crane: Thanks Jack. We continue to act aggressively on things we can control and really work on things that we can influence. We believe in the power market recoveries we repetitively said and we are managing our portfolio accordingly to maximize its profitability. Our investments in the utilities is very high priority. The stable earnings and the cash flow provided, will support sustainable dividend going forward. We continue to focus on cost cutting and driving the emergent synergies as we have discussed. We have talked about asset rationalization in the past and despite our best ever year in generation some of our nuclear units are unprofitable at this point in the current environment due to the low prices and bad energy policy that we are living with. Assessing the market operations and commercial policy solution is the focus right now. A better tax policy and energy policy would be the clear answer, but if we do not see a path to sustainable profits, we will be obligated to shut units down to avoid the long-term losses and that decision have the process should bring us to some conclusion by year-end. Our balance sheet strength enables us to invest in diversification. We will continue to add assets to the portfolio, that are earnings and free cash flow accretive. We will mitigate the market effects by pursuing aggressive costs cuts, asset rationalization and deploying capitals to drive growth. With that, we will open it up for questions. : Christopher M. Crane: Hey Dan. Dan L. Eggers – Credit Suisse Securities, LLC: I was wondering maybe can if somebody could just give us some thoughts or some color on what’s going on in the forward curves right now. Obviously we’ve seen a lot of movement in the 2014 curve, but 2015 and 2016 has been pretty benign so far. Is there a liquidity issue out there, is it a fundamental issue and you can kind of when do you guys expect that to start to move? Christopher M. Crane: Let me have Joe Nigro address that.

Hey Dan good morning. I think there is a couple of issues that we are dealing with. First since the end of the year, the West Hub power, if we use that as the first proxy, is up across the board and really that’s been driven by the changing gas basis that we’ve seen in the Mid-Atlantic and we really haven’t seen any heat rate expansion. We have price appreciation if you look at the balance of 2014 and 2015 and beyond across the board to West on the back of the gas bases change. The bigger issue is really in NI-Hub, because the gas bases really hasn’t moved if you look at 2015 to 2018 since the end of the year. We really haven’t seen a change in gas bases nor have we seen much of the change in the NYMEX price for natural gas. We’ve seen the calendar 2015 price at NI-Hub go up slightly about $0.50 or so. I think it was as of last night on an ATC basis. But we are actually down from 16% to 18% and I think your question about liquidity is spot on. There is absolutely no natural buyers on the forward curve in NI-Hub. And then on top of that there is very little speculation on being done in NI-Hub from a trading perspective. Certainly we marry those things together, we did not see it. And the last thing I would add is as you remember as we walk into the year, we saw the calendar 2014 ATC prices raised and hear rate expand slightly and I think it was the back of some retailers and others coming to market and cover, but we haven’t seen any change on the backend and we expect to see that until we see liquidity improve. Christopher M. Crane: And then Dan I’d just add, given the January cold weather issues and severe price volatility we’ve actually seen liquidity really back off just in a recent week. So, but NI-Hub liquidity is probably about as bad as we’ve ever seen it, and really even in 2015 there is almost no activities. Dan L. Eggers – Credit Suisse Securities, LLC: And can I guess kind of on the point we’ve seen the multiple retailers drop out of the business in January already. What kind of landscape are you guys seeing as far as competitors and maybe more departures in the business I guess A and then B. Are you having more conversations with customers looking to maybe reconfigure how they are buying power to get in to more firm contracts and things like that? Jonathan W. Thayer: Dan, there is a couple of data points to that, but first is there were a couple of wholesale solar procurements done in January. And I would tell you versus what we had seen in previous year, you saw some increased risk premiums and in some cases higher margins. I think that’s the first data point. The BGS auction will take place next week. The fixed price proportion next week and I think we’ll get another insight as to how people are thinking about it. From a retail perspective it’s really too early to tell, but I think you are right on. We have seen a number of folks announcing, they are getting out of the business, they are going to scale down the business. We have seen some small defaults return on expected in this kind of environment. I would fully expect that folks are going to take both year to reassess the risk rewarded suddenly growth volume products and when you think about the impending retirements that we’ve been talking about we use PJM proxy with some of the changes come as it relates to demand response bidding and just the GAAP basis issues we’ve seen as well pretty much all over the interconnect. I think it’s safe to say that we are going to expect people here to reassess what they think the value of a loan probably contracted and we would expect to see the volatility and the margins increase through time both retail and wholesale load volume contracts. Jonathan W. Thayer: And Dan, I would just reiterate what Jack said. Our matched load to gen strategy really has played out well here in January. While others are concerned about uncontrolled costs to serve load. With our robust asset base, our portfolio management capability in the wholesale side has allowed us to take those issues off the table and led our retail team focused on what the customer’s need, whether they are concerned about prices, if they are indexed or exposed at all and how we can help them get through this. I think that's our advantage in our mass gen to load strategy. And I think it puts us well ahead of a lot of our competitors. Dan L. Eggers – Credit Suisse Securities, LLC: So can I just take that to mean in the first quarter, that even with this volatility in January and into February on retail, the generation has offset that? So there has been kind of a net neutral so it hasn't hurt or helped appreciably? So can I just take that demand in the first quarter that even with this volatility in January and into February on retail, the generation is offset but there has been kind of a net neutral so it hasn’t hurt or helped appreciably? Jonathan W. Thayer: It’s certainly the talk, but we are right on plan. We don’t have any concerns about this weather and the volatility that has been in the market. Dan L. Eggers – Credit Suisse Securities, LLC: Excellent. Thank you, guys.

Your next question comes from the line of Steven Fleishman with Wolfe Research. Steven I. Fleishman – Wolfe Research, LLC: Yes, excuse me hi guys. Couple of questions; first and I’m not sure you can answer this, but on the nuclear plant et cetera, we are losing money in this environment, is there a way to give us a sense of how much lost earnings there is, let’s say in 2014 from plans that are not economic right now? Christopher M. Crane: Yes, we are not putting that out yet. If we have to make a decision, if again we will tell you the upside, but we don’t have that number to published yet. Steven I. Fleishman – Wolfe Research, LLC: Okay, I guess you had mentioned this in your remarks, but on the bottom of Slide 12, you talked about that you believe that you are going to have positive earnings CAGR, half of this 2014 guidance over the long-term. Should we assume that assumes you are kind of $2 to $4 power price recovery broader or is that something where even without all that given potential savings on new shutdowns and other things you are doing that might be possible even without that? Christopher M. Crane: Let me ask Jack go through the logic there. Jonathan W. Thayer: Steve, it incorporates a number of things. It incorporates our fundamental views both around power prices as well as capacity and that would provide an important part of that positive earnings growth, offsetting the declines that the forwards would suggest in the business. We also have a continued focus on cost that we are pursuing and building on top of the $550 million of savings from the merger and we expect that to also be additive and then we’ve factored in the available capital and balance sheet space that we have and the opportunity to use that for further investment in organic growth or potential acquisitions or other means of growing our EPS base. Steven I. Fleishman – Wolfe Research, LLC: Okay. Great, thank you very much.

Your next question comes from the line of Jonathan Arnold with Deutsche Bank. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Hi good morning guys. Christopher M. Crane: Good morning. Jonathan W. Thayer: Good morning. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Just sort of strategic question despite might be for Jack. Jack, in volatility and the recent volatility we’ve seen is kind of what’s going to ultimately inform the force, why don’t use some of that financial flexibility to be substantially left hedged? Jonathan W. Thayer: That’s in our outlook. I’ll let Joe Nigro to talk about that.

At this point in this cycle, if we talked about 2015 and 2016, until the only the two primary follow years that we are hedging, we’ve never had a larger opening power position at this point in over hedging cycle. So we talked a lot and Jack mentioned some of the things that we did in the fourth quarter in trying to selling gas and rotating out of a very long position and we took advantage of the price rise, we saw in natural gas from about mid-October through the end of the year. In early January, the gas market actually came off zone and we took the opportunity to buy back a lot of these hedging that we’ve put on. So we’re still carrying a very long open power proposition. The second thing I would add to that is, there has been some movement in prices when we talk about rest of them may have 2015 in certain seasons like summer and winter and we compared that to where we think ultimately they should settle given the fuel price environment we are in and then will give an opportunity to rotate positions and make power sales and really think its associated on the seasonal basis, but sitting here today we’ve never had a larger open power position at this point in the form of commodity cycle. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Okay, great. And then just one, because you mentioned that this restructuring of the gas or I guess its gas or fuel supply on New England, but if you are going to generate a lot less presumably that was a low-priced contract that’s going not to be as low-priced any more. So I’m curious is there a gain associated with that and when did it show up in 2013 as something that will be in 2014 or might not be thinking about that, right?

As we look at this, the way its flowing through our financial statement, you've seen it in the hedge disclosure. We restructured a 1 giga supply contract that was positive margin overall. You're right, we had a substantial decrease in the output of our generation up in New England that you see in the disclosure, to the tune of about 50%. The way the mechanics working and disclosure is such that we reduced our power new business to go and we added the value of that contract and we monetized into our estimated open gross margin, so the next change to the bottom line is zero, but it's just more in cash flow. Christopher M. Crane: Just the big driver of this is around making sure we have fuel reliability and flexibility and can run the plans when they are most needed on the system, that was a huge driver doing that. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: So is there a financial impact from the restructuring? Jonathan W. Thayer: The financial impact that you see, if you look at our hedge disclosures quarter-over-quarter; for example in 2014, you'll notice we reduced our power units to go by $150 million. We reduced it by $100 million. A good portion of that is the benefit of this contract and we're locking cash flows that we reduce the power usages to go and we have grossed up the gross margin for that balance. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Okay. Sorry to keep kind of on this, but does that mean there is not as an upfront gain associated with it? Christopher M. Crane: What they are trying to tell you it's built into the numbers you are looking at. There was an optimization that needed to be done for reliability upon this system that drove the contract restructuring. We were compensated for that and is in the numbers and it is positive, but it's in the numbers you see. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Okay. Can you quantify it? Christopher M. Crane: No, there is terms under the deal, no. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Okay. And then just finally Chris on your last comments around assets and everything, at EEI you talked a little about PPA's and then there was a sort of potential puff to addressing economic situation of some of the nukes and then there was a story about something being negotiated and Illinois round club cities. Can you comment at all about that? Christopher M. Crane: Yes. Somebody ran with a story that was not true. We are not negotiating with the state of Illinois on PPAs. What my statement was at EEI and still in pass forward, we would like to get longer-term contracts on especially the MISO assets. It is not being compensated for the reliability and we have origination folk out working on that, but it's not with a state entity, it's through multiple paths to other parties that are securing long-term needs. We'll continue to work on that. As you know there is not many of those deals out there, but MISO – and now MISO sales would be our target to try to find those opportunities. Jonathan P. Arnold – Deutsche Bank Securities, Inc.: Great. Thank you very much guys.

Your next question comes from the line of Hugh Wynne with Sanford Bernstein. Hugh Wynne – Sanford C. Bernstein & Co., LLC: Hi Chris, you had talked a couple of times about your efforts to achieve changes in energy policy that might benefit the Company and I was wondering if you could expand on that a little bit. Then in particular, what you are hoping to see done on renewables and on CO2 regulation and perhaps what do you think may play out on those two fronts? Christopher M. Crane: Our biggest push right now is at the federal and the state level is to stop subsidizing in generation. That's renewables and other sources of generation. It skews the market. It's doesn't give any of us the right signal should we be investing, should we be shutting down and we think that a good policy for the competitive market is let the assets compete. So, we've done a lot of work in the last couple of years trying to tell that story and we hope that it's continuing or will start to resonate with more of the stakeholders as we go forward the other thing that we're continuing to push on and explore. We do not get compensated as others for reliable baseload generation, we load a core, in a nuclear reactor we can run for up to two years with very reliable generation. We are not depending on the wind, the sun, or the flow of any fuel through the pipe it's there. So we think the capacity markets, not the energy markets should reflect the reliability and the dependability of those and Joe Dominguez and our regulatory folks continue to work in market space to try to find opportunities to improve the roles around that and we'll continue to push it. As far as greenhouse gases, we’re not advocating for a carbon bill. We spend a lot of time working on that in the past, and Washington I don’t think is the place to try to resolve that issue right now. We continue to watch what the EPA is doing and what they have under their jurisdiction right now as it's been pointed out to regulate going forward. We'll monitor that going forward, how we make our investments around that or how we would make our disclosures around that. But we are not in the advocacy spot right now in that area. Hugh Wynne – Sanford C. Bernstein & Co., LLC: Okay understood. Could you maybe just elaborate a little bit on what type of compensation you think would be appropriate for the reliable baseload as opposed to what you are receiving already in capacity markets? Christopher M. Crane: Yes, I’ll let Joe Dominguez touch on that.

Sure. So when we are talking about reliability, you are talking describe this fuel diversity or not allowing to get fuel on gas because of this volatility risks. The way I think that is being translated in stakeholder space, is you increase the requirements for firm fuel. And so obviously a nuclear unit has firm fuel, we load up 18 months of fuel in core. And the thought is that especially coming out of these winter events, the gas units will be required to have something that looks like firm fuel and that may involve firm transport requirements, it may ultimately involve a winter peaking season, whether it's an examination if whether sufficient gas can be provided to cover all the megawatts that are bid in the option. But those are the discussions that are better occurring. We think that will put upward pressure in the capacity market and allow nuclear units compensate from the firm fuel they have in the reliability they provided to the system. Hugh Wynne – Sanford C. Bernstein & Co., LLC: Great. So, you're basically hoping that the requirement for firm fuel supply and transmission on the gas plants will drive capacity prices higher and you will benefit accordingly, is that fair? Christopher M. Crane: Yes, but I don't want to be limited to that. I think what we need to figure out for the utilities on the system is whether the gas units will perform, fully more in peak season and now we're going to a peak in the winter and that's really what comes out of this. And I think the ISO's are going to examine a number of tests requiring firm transport is one of them, but the other way to do it is, you just whittle down the number of megawatts that could participate in capacity option. Either way, we will see some uplift in the capacity market as a result of those [Indiscernible]. Hugh Wynne – Sanford C. Bernstein & Co., LLC: Got it. Okay and thank you very much Christopher M. Crane: Sure

Your next question comes from line of Michael Weinstein with UBS. Michael Weinstein – UBS Securities LLC: Hi guys. On that same topic, could you talk about the PJM parameters that were released and what do you think capacity imports into PJM and how that might be changing? Christopher M. Crane: Joe Dominguez?

I think the most significant ruling was limiting the sub angle DR. And so we see the effect that already that's approved by FERC. FERC has not approved PJM's request on the import limits as yet. As you know they issued a deficiency letter. Our review of the deficiency letter suggests that they can answer the questions relatively quickly, re-file and be in time for decision by FERC in advance of the auction. In terms of the planning parameters, I think they would modestly reduce the number of imports, the number of megawatts of imported generation in this next capacity auction, that's my view based on what I've seen so far. Michael Weinstein – UBS Securities LLC: Honest projections. A couple of technical questions. Concerning the interest on ExGen just looks like in the guidance it went down to $325 million and the run rate of the fourth quarter would seem to imply about $400 million and net debt looks like it could actually increase. So I was just wondering what the cause of the decline in interest going forward?

Well, I think we can – I would say broadly that it's related to lower balance and we've been refinancing at lower levels. But why don't we take the more specific modeling questions offline. Michael Weinstein – UBS Securities LLC: No problem. And one last question. Have you baked into guidance any of the uplift from January like any of the risk – increased risk premiums or anything like that that might have happened or might be occurring, in your 2014 guidance?

No, we haven't, where you talk about it from a retail margin perspective where performance in January nonetheless convincing. Christopher M. Crane: We do think it should be and eventually will be. As we looked at these auctions or the muni [ph] aggregation process, we never could understand the numbers on some of the suppliers that are able to make, and so we didn't win a lot of those. We pushed – as we looked at our own models, the place that jumped out was the volume favorability, the VLR that can be directly seen in a weather event like that. So, we have previously priced that into our offerings that would – that portfolio management would protect us from events like we just went through. So, that's why we're seeing right now we're on plan. Michael Weinstein – UBS Securities LLC: Okay. Thank you very much.

Our next question comes from the line of Ali Agha with SunTrust. Ali Agha – SunTrust Robinson Humphrey: Thank you. Good morning. Christopher M. Crane: Good morning. Ali Agha – SunTrust Robinson Humphrey: Chris, as you are thinking through your strategic plan for 2014 and perhaps beyond that, but looking through this calendar year, where does the prospect for regulated utility M&A fit into your planning right now if at all? What kind of priority would you give that to build up your regulated base? Christopher M. Crane: So, right now, we are not in a position where we would want to trade our equity for anything other than something that was a relative value deal. So, if you look at – we believe we're undervalued at this point and there is market upside. Between the market upside and the current valuations we're being given, we think there is upside to that. So, we would hold our equity – use of our equity only to something that would be a relative value deal that we could see the upside accretion in earnings and profitability. Other things that would be looked at, would just be balance sheet type growth activities, as Jack has pointed out previously. So, off the balance sheet, we're willing to engage in anything that we can see on the near term as a positive accretion in earnings. But not create a dilution on the equity utilization just because we think most are trading at a premium. Ali Agha – SunTrust Robinson Humphrey: Okay got it. Also to clarify, you pointed out earlier also in Slide 12. When you look at your planning period and things are ultimately ending up with a positive CAGR in earnings. Are we looking at 2013 through 2018 or through 2016, what's the planning period, can you just define that? Christopher M. Crane: Put 2014 through 2018. Ali Agha – SunTrust Robinson Humphrey: 2014 through 2018. Got it. Thank you.

The next question comes from the line of Jon Cohen with ISI Group. Jon A. Cohen – International Strategy & Investment Group LLC: Hey good morning. Just a question on, when you say you have balance sheet capacity. Is that also looking out long-term through 2018 or is that more over the next few years? Christopher M. Crane: That’s looking out throughout 2018. Clearly we have more balance sheet capacity in the front years based on where the power curve is currently trending. To the extent that our fundamental view comes to fruition then clearly we'll have similar level of FFO relative to debt, that would create incremental capacity but consistent with prior comments. We think we are between $1 billion and $2 billion of balance sheet capacity into investing growth. Jon A. Cohen – International Strategy & Investment Group LLC: Okay, and if your fundamental view on the power markets does not come to fruition and does that kind of… Christopher M. Crane: That we arrive at $1 billion to $2 billion to the extent that our fundamental view comes to fruition than it's been equally higher. Jon A. Cohen – International Strategy & Investment Group LLC: Okay great and just one other question on the planning parameters; I noticed PJM broke out ComEd and BGE as separate LDAs, even though it looks like there is plenty of import capacity. Can you just talk about what their thinking was around that and does that help you at all? Christopher M. Crane: Joe Dominguez will answer that.

Sure. PJM is right under the tariff to separately model zone. When there are concerns that the megawatts supply needed within the zone won't receive adequate compensation through the RTO pricing into a liability criteria. As you indicated the ComEd zone, transmission the PECO [ph] ratio looks like it's pretty robust, BGE is a little bit tighter. But I think what this ultimately tells us is that as we get into the auction period, bidding practice within those zones is going to be very critical and what the cost of supply within the zone is going to be critical. PJM, we think wisely has taken steps to protect the liability in those zones by separately modeling the LDAs. Jon A. Cohen – International Strategy & Investment Group LLC: Okay. And can you just clear up one thing, as a nuclear generator, what is your flexibility for bidding in avoided cost, I mean it looks like they don't specify an avoided cost rate for nuclear, it's mostly for coal and other fossil units, can you bid something other than just being a price taker? Jonathan W. Thayer: The answer is yes, you can. There aren't the bulk rates, which is what you're pointing out, but there is nothing that prohibits nuclear from bidding an ACR. Jon A. Cohen – International Strategy & Investment Group LLC: Okay, great, thanks a lot.

Your next question comes from the line of Paul Fremont of Jefferies. Paul B. Fremont – Jefferies LLC: Thank you very much. It looks like for the year 2014, the effective tax rate came in at 33.8%, which is well below your guidance of 37.4%. I guess my question is what caused tax rates to be significantly better and also I don't see sort of a consolidated effective tax rate that you're assuming for 2014 in your guidance? Christopher M. Crane: We'll have our tax VP address that. Tom Terry? Thomas D. Terry Jr.: The guidance you've been given is just a core effective tax rate. The effective tax rate in the financials and what you'll actually see realize reflects the utilization of renewable credits, which drives that down substantially below what you get which is ongoing core tax rate. Paul B. Fremont – Jefferies LLC: So what is the consolidated tax guidance for 2014? Thomas D. Terry Jr.: Can we give that guidance? Christopher M. Crane: We don't provide that Paul. Paul B. Fremont – Jefferies LLC: Okay. And then is it again the renewable credits that's getting you to the much lower effective tax rate this year versus what you are originally guiding to? Christopher M. Crane: Yes. Paul you are seeing the continued build out of AVSR. You are seeing build out of wind generating assets through our renewable business. You should expect us to be a regular beneficiary of tax credits in lowering our overall tax liability on a cash basis as well. Paul B. Fremont – Jefferies LLC: Even though you can't give sort of a consolidated effective tax rate directionally, should we assume something similar to 2013 and 2014? Christopher M. Crane: Let us step back and look at how we want to discuss that. We've got more renewables coming on, we've got a pipeline. It hasn't been something that we've talked about in the past. I hate to do it on the fly right now. So let us regroup and we'll put something out or we'll address it on the next call. Paul B. Fremont – Jefferies LLC: Okay. And then just real quick on your discussion of the supply disruptions and what you're going to talk about in the first quarter of 2014, will that discussion essentially only impact your 2014 number or could it also have an effect on sort of future periods that you said that you were including in your disclosures? Christopher M. Crane: So, our disclosures are based-off of forward strip where we see the market on our short-term view doesn't come in to our disclosures. Joe?

Yes. Paul, couple of things; one thing is this. None of our January activity is in this disclosure that we released today. As you know and you see in the disclosure, we have new business targets to go from the power side and the non-power side. So, any value created whether it's in January or the balance of the first quarter for changes we see in value for the balance of the year would go towards meeting the business targets for the year. In addition, I think the question your are raising is what the value on the forward curve of some of the activity and disruption we've seen in January. As we talked about, it's been much more significant in the front-end of the curve and very muted on the back end of the curve, and we haven't seen anything in the two weeks instead of past that has led us to believe that our retail is changing, appreciably yes. But I do thing as we get to the end of the first quarter, we'll have better insight as to what the impact is on the forward curve as we move through time and what it means, but as of right now, our plan includes retail margins that we previously talked about when you think about like seeing on power that don't get back to the middle of that $2 to $4 range. If we see that expand, we would take that into account and recognize it to see it helps meet our new business targets or possibly expand them. Paul B. Fremont – Jefferies LLC: Okay. And last question from me, we've seen announcements of new gas plant construction in PJM, can you expect this to be limited to sort of the Pennsylvania, Marcellus region or do you expect to see more activity in other parts of PJM.

Paul, I think the general consensus is that you are going to see more in the Mid-Atlantic region prior to January 1, as you know, we saw substantial degradation in gas bases as it related to the Mid-Atlantic and the Marcellus area. It's not unreasonable to think you can see this in Ohio as well as the Utica shale starts to build out as quickly as people expect I do think though since we've seen an uptick in gas basis since the first of the year. You have to take a step back and pause and reassess what the economics of the trends are because there's going to be some very seasonal differences when you look at the curve being up if you then pervade sort of the proxy $0.30 to $0.35 on an annualized basis. There is a big winter component to that whereas the summer and the shoulder months are still weak, but in general I think you would see it in Marcellus and Utica region. Paul B. Fremont – Jefferies LLC: Thank you very much.

We have time for one last question.

And your final question comes from the line of Michael Lapides with Goldman Sachs. Michael J. Lapides – Goldman Sachs & Co.: Hey, guys I am going to make it easy on you asked and answered, I will follow up after the call. Christopher M. Crane: Thanks.

Okay. That ends our Q&A session. Thank you very much. Christopher M. Crane: Thank you.

This concludes today's conference call. You may now disconnect.