Kevin W. Hadlock - VP of IR Mayo A. Shattuck, III - Chairman of the Board, President and CEO Thomas V. Brooks - President, Constellation Energy Resources; and EVP, Constellation Energy Group Michael J. Wallace - President and CEO, Constellation Energy Nuclear; and EVP, Constellation Energy Group John R. Collins - EVP and CFO Andrew L. Good - CFO, Constellation Energy Commodities Group

Daniel Eggers - Credit Suisse Kevin W. Hadlock - Vice President of Investor Relations: If I could ask everybody to take your seats, we're going to go ahead and get started. For you that are listening via the web and phone, we're just gathering here in New York. But I would like to thank everyone for joining us here today. I am Kevin Hadlock, Vice President of Investor Relations and Financial Planning and Analysis. Welcome to our 2008 Analyst Presentation and Fourth Quarter Earnings Call. I'm glad so many of you could join us today here in New York. Before we begin our presentation, let me remind you that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. For a complete discussion of these risks, we encourage you to read our documents on file with the SEC. Our presentation today is being webcast and the slides are available on our website, which you can access at constellation.com under Investor Relations. On slide three, you will... notice that we will use non-GAAP financial measures in this presentation to help you understand our operating performance. We have attached an appendix to the charts on the website reconciling non-GAAP measures to GAAP measures. Throughout this presentation, we will provide information shown in a new integrated Merchant framework to assist you in modeling and valuing the company's business activities. This information should be considered preliminary and we will… will be subjected to changes as we refine our estimates associated with the components of the Merchant segment. With that, I would like to turn the time over to Mayo Shattuck, Chairman, President and CEO of Constellation Energy. Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Thank you, Kevin. Good morning, everybody. I'm glad to see that all of New York is not yet shifted out to Arizona. Thank you for coming, and thank you for everyone on the webcast for attending this morning. So here is our agenda for the morning. First, I'm going to provide some perspective on industry trends and strategic outlook. After that, Tom Brooks, the President of our Integrated Merchant Activities, will provide an overview of our competitive businesses. Following Tom, Mike Wallace will discuss Constellation Energy's new nuclear initiative. And then finally, John Collins, our Chief Financial Officer, will cover the financials. And after John, we'll have time for questions. In addition to the presenters, there are a number of other Constellation business leaders in attendance here today. We've provided bios for all the executives in attendance. Following the meeting, please introduce yourself to them and ask them any additional questions that you might have. Let's begin on slide five. This management team is sharply focused on delivering results, and in 2007 we had another outstanding year. We grew earnings by 27% and generated adjusted earnings of $4.60 per share. This performance was towards the top of management's upwardly revised guidance range of $4.45 to $4.65 per share. Our earnings growth rate outpaced the S&P Electric Utility Index and the S&P 500 by at least 10 percentage points. I'm very proud of our employees and the management team for their dedication and focus on execution that helped deliver these excellent results. Our success in driving strong earnings has translated into significant total return for shareholders. Considering both stock price appreciation and dividends, we delivered total shareholder return of 52% in 2007 following the 23% and 35% total shareholder return realized over the last two years. In addition, we announced this morning that we will grow our 2008 dividend by 10% to $1.91 per share. In 2007, we made significant progress on our new nuclear initiatives. We formed the UniStar Nuclear Energy joint venture with EDF in August, with EDF committing to invest up to $625 million as we achieve certain milestones. UniStar Nuclear Energy is making progress on COLA's for two potential constellation nuclear plants as well as for other partners. We are seeing strong federal support as evidenced by the establishment of a workable federal loan funding program in December. We continue to expand our Merchant capabilities by building the foundation to make significant multi-year investments in generation to expand capacity and enhance reliability. Through several acquisitions, we also grew our wholesale load-serving business in the regulated Southeast market, added to our upstream gas reserves, and expanded the geographic footprint of our retail gas operations in the Midwest. At BGE, we implemented several key components of the Smart Energy Savers Program and recently approved for the demand, response, and energy efficiency programs from the Maryland Public Service Commission. We are also in the pilot phase for an advanced metering initiative. All of these programs will provide BGE's customers with the tools and incentives to better understand and manage their energy usage. Over the next five years, we expect to increase capital investment in BGE to keep pace with customer growth and increase reliability. In summary, we delivered superior earnings growth and grew strong total shareholder return for our investors in 2007. As you will see throughout the presentation, we are poised to continue our success in 2008 and beyond. Turning to slide six, prices for commodities have risen sharply in recent years at both the wholesale and retail levels. However, you will note that while electricity prices have risen, reflecting the higher cost of fuel inputs and much higher construction costs, they have not risen as rapidly as other commodities. This is supportive of the notion that competitive markets are working to effectively soften the impact of rising input costs. Regardless of whether customers are served in a regulated utility market or a competitive generation market, all customers over time will see the impact of higher commodity prices in their energy bills. However, by investing in our generation capacity combined with innovative efficiency and demand response solutions, Constellation is focused on helping wholesale and retail customers alike to manage energy costs in this market environment. On to slide seven, in addition to the increases in commodity prices the customers have experienced over the last several years, the market is increasingly focused on the need to stabilize greenhouse gas emissions in the U.S. electric sector. This chart is from the Electric Power Research Institute and one that you should be very familiar with that’s used frequently, illustrates the potential path to slow, stop, then reverse the rate of greenhouse gas emissions. Efficiency programs in renewable energy are represented here by blue and green and are the near-term catalysts for reductions in CO2 emissions. Some of the technologies depicted here such as carbon capture and storage are unproven and are unlikely to be commercially viable for some time. Nuclear power of course is well proven, and we believe that in the decades ahead nuclear power can and will play an increasingly important role in energy mix. We also believe competitive energy markets are the platform for technology innovation that must occur if the goals now being contemplated in federal carbon regulation are to be met. On slide eight, Constellation is meeting the challenge of reducing our operational impact on the environment. As we have discussed with you in previous meetings, we are planning for significant environmental capital spending over the next several years. We are making progress on the construction of the Brandon Shores scrubber that will substantially reduce SO2 and mercury emissions from the plant. We are supportive of Maryland's involvement in the regional greenhouse gas initiative or RGGI because we think it is important to establish a market price for CO2. Over time we expect that a federal policy will be implemented to supercede regional initiatives like RGGI and align the U.S. with the global efforts to reduce greenhouse gas emissions. On slide nine, today our businesses are environmentally focused and we are proactively moving to improve our position. We are proud to have one of the lowest emitting generation fleets with more than 60% of our megawatt hours coming from low emitting nuclear and hydro sources. Looking into the future, our generation operations are strategically positioned in location and fuel type to provide highly valued energy products in a carbon-constrained economy. Our customer-focused businesses are actively engaged on the demand side. Our retail businesses have expanded product offerings to include demand response and renewable energy products. At the Global Commodities Group, we are active in emissions markets for SO2, Nox, and carbon, especially in Europe. In December, we announced that we are investing in the Green Exchange, which will offer trading in global carbon-based contracts. In addition, we are contracting with renewable energy providers to secure renewable energy credits for our customers. You already heard in this presentation that we are investing in several program at BGE to provide our customers with the tools and incentives to address and manage their energy consumption and ultimately lower their energy bills. By leveraging our large customer base and understanding their requirements, we expect to capitalize on the market's evolution to be increasingly environmentally conscious. Now on to slide ten, Maryland, as you saw in our press release this morning we have reluctantly concluded that we have no choice but to file a federal action to enforce our rights under Maryland's 1999 Industry Restructuring Settlement Agreement. Earlier this month, the Maryland PSC's interim report to the legislature on stranded costs in the 1999 settlement injected a profoundly destabilizing element of uncertainty into the regulatory climate and energy marketplace in Maryland. We cannot abide by efforts to make hindsight judgments about decisions and agreements that were made nearly a decade ago by multiple parties in full accordance with the law. It is difficult to understand the Commission's desire to revisit issues that have been fully resolved and upheld by the Maryland Courts. We are confident that the federal courts will arrive at the same conclusion as those Maryland Courts did, which is that the settlement was fair and commendable. We must have the certainty that this reaffirmation will provide. The stability of the state's energy policy rests on the sanctity of contracts, including settlement agreements such as this one. And because this report has a potential to undermine the confidence of market participants by raising questions about how they could expect to be treated by the state in the future, we have been systematically explaining to the legislature and the Governor's office the serious errors, emissions, and mischaracterizations in the report. No one should interpret this report as an accurate portrayal of the facts. No one should believe that there is any basis for attempting to undo this longstanding settlement. So I would ask everyone here, in your binders there are materials here that explain specifically our rebuttal to a number of the points issued in that report. I am not going to delve today on the mechanics or details of our litigation strategy except to say that we have informed the Maryland Attorney General that we are terminating the litigation standstill agreement, which has been in place since November of 2006. That agreement pertained to the $386 million, which we believe was unconstitutionally taken in Senate Bill 1 in the summer of 2006, including nuclear decommissioning trust dollars. The 1999 restructuring settlement established a method of collecting those dollars and capped the nuclear decommissioning liability that rates their space for those funds. One objective of our suit will be to remove the unwarranted uncertainty surrounding the disposition of those funds, which the PSC’s report has wrongly inserted into the dialog about Maryland's energy future. We recognize our responsibilities in Maryland and pride ourselves on playing a constructive part in the state's energy infrastructure and marketplace. We are planning to undertake a very large capital expenditure program in the years ahead in Maryland and elsewhere. In so far as we are planning to invest in improving reliability of existing plants and expanding capacity in Maryland, we must have the confidence in the political and regulatory environment in which we operate. We will always be a part of a fair and productive dialog about how best to improve laws and regulations. So when we see attempts to rewrite history or exert pressure on legitimate agreements, we will act vigorously to protect the interest of our shareholders. Turning to slide 11, meanwhile there are some positive policies being offered to the legislature in regard to conservation and efficiency, and we hope to work with lawmakers and non-governmental organizations to make progress in these areas. As you know, BGE is creating what we believe to be a world-class program of customer-oriented conservation and demand response initiatives. We believe strongly in the value of making efficiency a centerpiece of energy policy. The big picture is this. The imparities of reliability, affordability, and sustainability are squarely on the table in Maryland as they always are in every market. And we are confident that market participants will invest capital in the state's energy infrastructure to meet these three needs as long as Maryland fosters an environment where investments can receive an adequate return. Policymakers must have the wisdom to allow market forces to work and resist the temptation to intervene in natural supply and demand economics. Before I turn the call over to Tom Brooks, let me summarize the investment pieces in Constellation Energy. First, we know when you invest in Constellation you in large measure are investing in the management team, which has delivered superior results over the past six years. We have predictably and consistently achieved or exceeded earnings guidance through a variety of market conditions. Our disciplined focus on managing through the full commodity cycle has allowed us to perform well in both up and down commodity price environments. Second, we see clear and substantial earnings growth in the coming years. We are reaffirming guidance for 2008 of $5.25 to $5.75 per share and expect to be in the middle to the upper end of this range. This represents 15% to 22% compound annual earnings growth from 2007 to 2009. Third, as we look to the future we feel like we have the wind at our backs. We are well positioned to deploy capital to pursue strategic market opportunities. We have a solid foundation built upon a well-managed type quality asset base. Our focus on customers and market leading position in power and our strong position in gas and coal markets continue to give us an information edge and scale advantage over our competitors. Our industry leading risk management capabilities and our disciplined investment approach help us make sound investments and optimize their value. Finally, our strong balance sheet provides us the financial flexibility to act quickly and capture opportunities. With that, I'd like to turn the podium over to Tom Brooks to discuss the outlook for our Merchant business. Thomas V. Brooks - President, Constellation Energy Resources; and EVP, Constellation Energy Group: Thanks, Mayo. Good morning, everyone, and thanks for joining us today. I'll spend the next few minutes discussing our Merchant businesses starting on slide 14. Constellation's Merchant business is comprised of Generation, our Customer Supply Group, and our Global Commodities Group. Our nuclear and fossil generation teams operate 8700 megawatts of mostly baseload capacity located in Central New York and Southeast PJM. Our generation team is focused on maximizing the contribution margin from our fleet and increasingly on developing opportunities for new investments. Our Customer Supply Group is the market leader in providing electricity and natural gas products to wholesale and retail customers throughout North America, and our Global Commodities Group is a risk manager, market-leading trader, and developer of our structured products in energy investments portfolio. Turning to slide 15, let me now talk about each of these areas in more detail beginning with Generation on slide 16. The key themes that underpin our power generation strategy are fairly simple. Nationwide demand for electric power continues to climb roughly with GDP. Supply additions are not expected to keep pace through the end of the decade. Predictably, capacity margins are tightening. In addition, while power prices have risen over the last three years, the cost of new construction has risen even faster. The result is that even in the phase of a tightening supply-demand balance, market prices support new investment in only limited circumstances today. Given long lead times for a new supply, we expect a continued trend of tightening reserve margins over the next five to ten years, which should support investment in new capacity as prices respond. If this trend plays out, it will likely benefit our existing fleet and create opportunities for us to make investments in new generating capacity. We're very focused on both. Turning to slide 17, our fleet is well positioned to benefit from today's market environment. First, we own efficient assets in valuable markets. 97% of our capacity is located in New York and PJM and should benefit from declining reserve margins in these high demand regions. Second, our baseload plants are becoming more valuable as new-build costs have escalated and new environmental constraints make constructing coal-fired capacity much more difficult. Because our fleet is largely baseload, we should benefit if natural gas prices continue to escalate in the long-term. Finally, our environmental position is advantaged by our fleet's low CO2 emission rate of 0.4 tons per megawatt hour. The industry average is 50% higher. So we believe we're well positioned to respond and benefit from essential CO2 legislation. Let me now turn to the earnings outlook for our fleets starting on slide 18. We view EBITDA before hedging as the most useful indicator of the value of our Generation. We expect unhedged EBITDA of about $2.35 billion in 2008, up 18% from 2007. The current forecasted GAAP between our results before and after hedging will diminish as our hedges mostly roll off by 2011. Since we hedge consistently, and without directional price bias, our results after hedging should yield a realized average price in line with the market over the full price cycle. Therefore, the long run average value of our hedged portfolio should be about zero. Turning slide 19, due to our hedge program our results after hedging will be relatively insensitive to changes in the commodity markets over the next three years. In the current year, our relatively small amount of unhedged Generation length is managed within our global commodities portfolio. Consequently, for 2008, our Generation EBITDA after hedging will vary from the forecast shown on the prior page, mostly as a function of reliability performance and operating efficiency, not market prices. For 2009, we estimate that $1 per megawatt hour change in power prices would change our Generation EBITDA after hedging by $4 million from the forecast shown. A change of $0.10 per million Btu on a fuel input would change our 2009 EBITDA by less than $1 million, all else held equal. We also have substantially hedged our capacity position. We have factored the prices of these sales into the hedged EBITDA forecast shown on the prior page. So our earnings after hedging will not be very sensitive to changes in capacity prices through 2010. Turning to slide 20, given that our fleet is largely base load, the key operational metrics that can cause variability in our results, our total energy output, and forced outage rate, which affects both energy production and penalties under PJM capacity program. Over the last several years, we've accomplished very steady performance relative to both metrics. For perspective, 1 percentage point increase in our fossil reliability would increase our EBITDA by about $8 million. A 1 percentage point increase in our nuclear capacity factor would increase our EBITDA by about $16 million. Turning to slide 21 and a discussion of our new development opportunities. In addition to the positive outlook for our existing fleets, the market environment has become conducive to new development under certain circumstances and we are presuming targeted opportunities in three categories. First, capacity expansion projects, which include investments at existing sites to increase capacity and one small Greenfield development in Alberta where the regulatory environment is supportive of new investments. These projects are expected to yield a total of about 370 megawatts of operating capacity at an installed cost of about $330 million. At about $900 per KW, this compares to quite favorably to our estimate of a weighted average replacement cost for similar Greenfield capacity of about $1600 per KW. Second, reliability enhancements projects, which are designed to improve our operational liability in response to the new RPM capacity program, over the next year we expect to invest about $50 million at units with an operating capacity of about 720 megawatts. And third, potential future development projects, which we are pursuing to create the options to invest when market conditions are supportive, they include new gas fired generation in Maryland as well as new nuclear, which Mike Wallace will update you on in a moment. In addition to these capacity development projects, you will recall that we also expect to invest about $1 billion in capital upgrades to improve environmental performance at our coal-fired units at Brandon Shores, Wagner, and Crane in response to Maryland's Healthy Air Act. The largest element of this program is a project to construct a scrubber and baghouses at Brandon Shores. This project has been underway for nearly a year and is proceeding on schedule. Turning to slide 22… let me now focus on Customer Supply starting on slide 23. Our Customer Supply group provides power and natural gas products to wholesale and end-use customers throughout North America. Our three key markets are wholesale power, retail power, and retail natural gas. For 2008, we expect to generate gross margin of $737 million, comprised of 41% wholesale power, 42% retail power, and 17% retail natural gas. Turning to slide 24, we have an active presence in all the regions of North America that are open to wholesale or retail competition. Our largest bases of operations are in Baltimore and Houston where our power and natural gas risk management groups are located. In addition, we have a network of 40 sales and customer service offices allowing direct interaction with customers as well as knowledge of and participation in regional regulatory matters. Turning to slide 25, our Customer Supply group turned in a very strong performance in 2007. This result was led by our retail power group, which increased its gross margin by more than 40%, driven by realizations of 2006 sales originated at attractive margins. Likewise our wholesale power group delivered its strongest gross margin year ever. Looking forward, we expect that due to tightening of new sales margins that we experienced in 2007, neither wholesale power nor retail power will experience quite as strong a year in 2008. However, we are extending our retail sales capabilities to pursue smaller commercial customers and the indirect broker channel more fully in 2008, which should partially offset the impact of the margin compression we saw in 2007. Our retail gas business had a more mixed year. Despite increasing our volume of delivered gas, our bottom line earnings from retail gas were down due to several operational issues. Over the last five years, we grew by acquiring smaller gas marketers, but did not start to fully integrate them into our platform until the start of 2007. As our retail gas infrastructure had not get pace with topline growth, we experienced some operational issues in 2007 results that hurt results. These have been rectified by integrating retail gas into our overall merchant platform, and we are confident in the outlook for both topline growth and operational performance going forward. Turning to slide 26, we've served retail... we've served wholesale power, retail power, and retail gas markets for a number of years and we've steadily increased customer volumes delivered. Over the last five years, we have achieved double-digit annual growth rates in both power and natural gas volumes. We continue to see opportunities grow by acquisitions, organic growth, and by penetrating new markets. So we expect to see this trend continue. Turning to slide 27, turning to the margin side, Constellation has been a Customer Supply leader for nearly a decade. We have a deep experience with the factors that influence customer demand and competitive intensity. In general, we believe the Customer Supply markets behave similarly to some specialty insurance markets. Over a period of years, margins have shown cyclicality, driven by various forms of event risk such as supply shocks, extreme weather, or the uncertainty caused by major regulatory action. Generally, margins tend to increase quickly after events that cause some suppliers to experience losses and they tend to gradually compress during an extended period without such events. 2007 was a year that clearly exhibited some margin compression in wholesale and retail power. Spot power price volatility has been fairly muted since the supply shocks caused by hurricanes Katrina and Rita in the fall of 2005. As a result, we've seen declining day-one margins for the last 18 months or so with average wholesale margins in 2007 reaching historic lows for new sales. Average retail power margins have followed a similar pattern with large C&I margins historically ranging $0.50 to $2 megawatt hour higher than wholesale margins. Along with declining margins in 2007, we experienced a bit lower than expected sales volumes as we maintained pricing discipline. On the other hand, our realized margins in 2007 were very strong based on the impact of long-term sales entered into in late 2005 and early 2006. On the retail natural gas side day one margins were fairly stable over 2006 and 2007 averaging $0.15 to $0.20 an Mcf and sales volumes were about in line with expectations. Turning to slide 28, given our basic model of selling energy products to customers over turns typically ranging from six months to two years, our Customer Supply business is supported by a backlog of gross margins sold in prior periods and expected to be realized in future periods. Note that our 2008 backlog of $535 million represents about 73% of our expected 2008 gross margin, slightly better than the backlog of 71% of gross margin in last year's plan at this time. Turning to slide 29, turning briefly to growth opportunities in 2008 we will be targeting growth in three key areas of our retail power business, sales through brokers and aggregators, sales to smaller commercial customers, and sales of demand response products. As you see outlined here, while we've been active in these areas in prior years, we have a series of initiatives planned that should drive meaningful growth and our presence in each area. In 2007, these components of our retail power business contributed $70 million to our backlog. Our 2008 plan contemplates that these areas will add about $125 million to our backlog over the next 12 months. On the wholesale power side we have significantly expanded our footprint in 2007, adding more than 3000 megawatts of peak load in non-ISO markets in the Southeast, particularly Georgia. We expect to see more growth in non-ISO markets in the future. Finally, in retail gas we completed the acquisition of Cornerstone Energy in 2007, which will increase our volume by about a third. Turning to slide 30, looking at our Customer Supply earnings picture you can see the impact of cyclicality on the sales margin. Between 2005 and 2007, gross margin increased 34% annually, in part reflecting the impact of longer-dated, higher margin sales entered into after the hurricanes of 2005. We expect an 8% decline in gross margin from 2007 to 2008, in part reflecting the impact of declining new sales margins on the power side throughout 2006 and 2007, which will spread to lower volatility in the absence of price shock events. The operating expense line shown here includes an allocation from our global commodities through our Customers Supply group since the units were partially commingled historically. Over the 2005 to 2008 period, we expect operating expenses and gross margin to increase at about the same rate annually in spite of significant investments to broaden the business through acquisitions and new market entry. In total, we do not expect our 2008 customer supply EBIT to be quite as strong as our outstanding 2007 result, but we do expect a strong year. We expect EBIT to grow annually at 17% from 2005 to 2008. Turning to slide 31, let me now focus on our Global Commodities Group starting on slide 32. Our Global Commodities Group handles all of Constellation's risk management and overseas merchant risk-taking activities in energy markets. Our 2008 plant gross margin of $828 million will fall into three categories; Portfolio Management & Trading comprising 47%; Structured Products, comprising 28%; and Energy Investments, 25%. Let me touch briefly on each area starting on slide 33. Our Portfolio Management & Trading group manages all the price risks associated with Constellation's Generation fleet, our Customer Supply business, both wholesale and retail, and our Structured Products portfolios. It also deploys risk capital in traded energy markets. Our Portfolio Management & Trading activities are supported by a very strong market position. We have been the number one player in U.S. power markets for the last five years. We have also become the third largest player in North American gas markets with the only larger players being integrated oil and gas majors. This market position supports strong and steady results that you see on the lower part of this chart, results that we think are particularly impressive given the significant volatility that energy markets have experienced over the last five years. Turning to slide 34, in Structured Products we originate longer-term customer risk management transactions in three key areas. Contractually controlled power generation includes margin from long-term contracts we've entered into to purchase power from generators in support of our Customer Supply activities; U.S. and the international coal sales through which we delivered $22 million short tons of coal to a variety of power generation and industrial customers in 2007; and natural gas transportation and storage, which includes results from managing our contractual network of natural gas storage and transportation capacity, which also backs out supply to our customer business. Earnings from these activities are generally recognized as the fiscal commodities are delivered. As you see, our total structured products backlog amounts to $612 million to be realized over the next five years. Turning to slide 35, finally our Global Commodities group has also made a number of direct investments in energy-related assets. These have been strategically connected to our other business and were relied up on our core skills in valuation and risk management. It had been in two key areas, natural gas production and dry bulk freight. In total, we have invested just under $1 billion, mostly in the last two years, and generated a gain, both realized and unrealized, of about 40%. Over the coming year, we expect to realize gains from some of our current investments and redeploy capital into further direct investment opportunities in areas strategically connected to our business. Turning to slide 36, looking at the Global Commodities earnings picture, three things are worth noting. First, we are experiencing meaningful growth from Structure Products in energy investment areas where we’ve focused significant business building effort over the last two years. Second, our outlook for Portfolio Management & Trading in 2008 is generally in line with realized results from the last two years with a bit of a bias to the conservative side. Our operating expense ratio has stayed within a reasonably consistent range over the last three years. The ratio did increase somewhat in 2007 as we expand... as we invested to expand our structured products and energy investments capabilities. But we expect the ratio to decline meaningfully in 2008 as we realize the benefits of this 2007 investments. In total, we expect EBIT to grow at an annual rate of 21% over the 2006 to 2008 period. Turning to slide 37, let me quickly summarize starting on slide 38. As you’ll recall, during 2007, we combined our retail power, retail natural gas, and wholesale mid-market and load serving businesses under one management team. Our Global Commodities people now handle all of the supply and risk management functions for our Customer Supply group and our Generation fleet. We also combined mid and back office functions to leverage scale and improve efficiencies. This has led to some cost leverage. We expect Phase I integration efforts to produce $15 million to $30 million in annual cost savings by 2009, part of which has been achieved already and is included in our 2008 plan. We may see additional benefits as we streamline processes in 2009 and beyond. Turning to slide 39, to close, our key priorities for 2008 are simple. In Generation, we will be focused on operating efficiently and executing on capital projects to expand our capacity and improve our environmental performance. We will also continue to drive reliability enhancements in response to the new market signals created by the RPM capacity program. In our Customer Supply group, we will be absolutely focused on driving sales and we’ll expand our presence in growth segments where we see opportunity. In our Global Commodities group, we'll continue executing on our return oriented investments trading and risk management approach. Now, I'd like to turn things over to Mike Wallace to discuss our new nuclear initiatives. David W. Carlson - President and CEO, Constellation Energy Nuclear; and EVP, Constellation Energy Group: Thanks, Tom, and good morning, everyone. In my presentation, I am going to provide an update on Constellation Energy's new nuclear activities and the steps we are taking to capitalize on the opportunities in today's market to pursue new nuclear development. To begin on slide 41, a number of driving forces are coming together that are particularly supportive of new nuclear plants being built in United States. We are experiencing falling reserve margins, particularly in the Mid-Atlantic, West Coast, and Texas regions, but also across the country to some degree. Combining this with the increased focus on energy security and the environment as well as raising natural gas prices, nuclear energy is becoming a cost competitive, clean alternative for baseload generation. Today, we are experiencing a significant increase in public support with 64% of public opinion now in favor of new nuclear. Additionally and very importantly, we have Congressional support from the Senate and the House, Republicans and Democrats, as well as with the current administration, most readily manifested in the passage of the Energy Policy Act of 2005. In summary, great progress has been made over the last few years as we have increased our focus on energy independence and global climate change, bringing nuclear power back into the energy mix. Today, momentum continues and as we are working to make new nuclear a reality. Turning to slide 42, Constellation Energy took its first step in 2005 when we formed UniStar to pursue new nuclear development activities by jointly marketing the USEPR technology with Areva. Since then, we have been working to position Constellation and UniStar as the US leader in the nuclear renaissance. One of the crowning achievements of our strategy was the establishment of our joint venture with Electricite de France last August. In establishing our new nuclear initiative with EDF, we have secured a great partner and a world leader in nuclear power who is well respected for their design, construction, and operations expertise. We also benefit from the fact that they are building the second EPR, which is currently under construction at their Flamanville site in the Northwest of France. It is due to come on line in 2012, about three years ahead of the activity in the U.S. We have brought to the partnership our nuclear expertise in the U.S. and our existing nuclear sites, especially Calvert Cliffs and Nine Mile Point. Together, we will draw up from each other's experience and expertise, and we will benefit from EDF's first hand experience at Flamanville. We will have direct knowledge of data from Flamanville construction and the experience of team members from EDF working on the project in France. The strength of our team goes beyond our partnership with EDF. Our joint venture with Areva was the first foundation block for UniStar as we indicated that we were pursuing four standardized units as the base fleet going forward. We also identified Bechtel as the constructor that we will use for the USEPR. Most recently, in November, we added Alstom to the team as the supplier of turbine generators for those units. Our approach has been to build a world-class team of suppliers who will be able to assure standardization and best practices in the USEPR. In addition, the validity of our model has been demonstrated in the marketplace as Ameren has engaged with us for the development of their license application, and most recently PPL engaged with us to assist in the development of their license application. Turning to slide 43, so let's look specifically at the timeline for building the first USEPR. We are pursuing the opportunity to build at either our Calvert Cliffs site in Maryland or our Nine Mile Point site in Upstate New York. At this point, Calvert Cliffs is the reference site for our COLA, which we plan to file in March. We identify this as a potential timeline since we have not yet made the final decision to construct the new nuclear plant. Nevertheless, all of the front-end activities shown on this chart in 2006 and 2007 have been accomplished. The design certification has been filed with the Nuclear Regulatory Commission, part of our combined operating license application has been filed in docketed with the rest to be submitted in March, and our state permit application was filed in Maryland in November. The data collection at the site has been completed in support of these applications and they are now under review. Turning to slide 44, as we have progressed over the last three years, we have taken a risk-managed approach to pursue a new nuclear development to drive down the level of uncertainty. A watershed event occurred in 2005 with the passage of the Energy Policy Act, which enabled us and others to seriously consider building the next generation of nuclear plants in the U.S. Even so, the risk profile for a new nuclear at that time was quite high. While there are many risks we monitor, analyze, and manage, we have identified about a dozen high level risks that must be appropriately addressed before making a final commitment to build. In 2005, we would have considered all of these as read. As I stand here today, the Constellation team and the broader industry have worked hard to manage and mitigate a number of these issues, and we have become confident that several of the risk issues are now actually green and not a strong concern. While a number of them are yellow and still require monitoring and active management, we focus our most significant attention on the highest risks, the red issues. One of the key issues of focus for us is developing a detailed cost estimate for building the next generation plant. As I am sure you are aware, there are many variables to this equation and we are working hard with our various partners, Areva, Bechtel, Alstom, and EDF to develop a solid cost estimate. We are fortunate to have a partner, EDF, from whom we can draw our first-hand experience from the construction of their Flamanville 3 plant to assist in developing our cost profile. In addition, we are focused on efficiencies through modularization and other state-of-the-art construction techniques that were not able to be used the last time nuclear plants were built. We are well aware of the risks of building a nuclear plant and continue to emphasize our disciplined risk management approach to making decisions and future commitments. Moreover, we are making contract commitments only as and if needed and building in appropriate off-ramps and options as appropriate. It is our expectation as we continue to work these various risk issues that we should be in a position at the end of 2008 or early 2009 to make the decision to move to the next significant level of financing for the project, performing site work, and getting our license in 2011 with a focus on our commercial operation date of 2015. Overall, we have been managing the risk environment and as a result the overall risk profile is greatly improved in supports to the continued expansion of nuclear development activities. Turning to slide 45, in summary we have been exercising leadership in the nuclear industry since 2005 as we pull together a strong team and made the decisions that have moved us forward over the last three years. We continue to take a very disciplined, risk-managed approach as we do in all our businesses. Moreover, the partnership with EDF was a significant building block, bringing funding into UniStar that aviates the need for Constellation to make any additional cash investment in the joint venture for the next 12 to 18 months, which will be the most critical time for us as we work on the major issues to get to a point where we can make the decision to move forward with constructing a plant. We clearly have the right team, our suppliers, partners, and customers who are working with us for the submittal of license applications for the USEPRs. We have selected the right technology with the highest safety and security margins and licensed in both Finland and France. Two European units are under construction with the Flamanville unit in particular being the baseline unit for the USEPR and the one we will work most closely to replicate. We believe it is the right time. Market factors and environmental benefits are very much in support of new nuclear. Most significant were the passage of the Energy Policy Act of 2005 and Congress action in December to assure with the deal we had the authority to move forward with a loan guarantee program. Constellation Energy has established itself as an industry leader and has developed and implemented a model that balances the risks and benefits of pursuing the successful development, construction, and operation of new nuclear in the U.S. And with that, I thank you, and I will turn it over to John for the financial review. John R. Collins - Executive Vice President and Chief Financial Officer: Thank you, Mike. Good morning, everyone, and welcome to New York. I'm glad to see you today. Let's begin on slide 47. I will start this morning by highlighting a few of our financial successes during 2007, then review our 2007 results before turning to a review of 2008 forecasted results. I will wrap up by reviewing our financial outlook beyond 2008. Moving to slide 48, as Mayo discussed earlier, 2007 was another strong year. Let me start by highlighting several of our key financial successes. We continued our strong track record with earnings growth of 27% over a strong 2006. As a result, we landed in the top end of our revised guidance range that we provided to you in October. I will provide additional 2007 earnings details in a minute. As Mayo mentioned, we delivered total shareholder return of 52% in 2007, well above both the S&P Utility and S&P 500 indices. In June, we successfully completed the issuance of $623 million of rate stabilization bonds associated with the delayed transition to market rates for BGE residential customers. We completed the financing roughly one year after enabling legislation was approved, which is one of the fastest executions of a utility securitization. As of January 1 of this year, all of BGE's residential customers have completed the transition to full market rates. In July, we refinanced our existing liquidity faculties into a $3.85 billion, five-year revolving credit facility. This provides a long-term sustainable liquidity cushion to support the growth of the business over the next five years. As previously discussed, we formed the UniStar joint venture advancing our new nuclear initiatives. As part of this agreement, EDF is permitted to purchase up to 10% of Constellation stock in the open market with a 5% limit in the year of the agreement. In October, our Board authorized a $1 billion share repurchase program, of which we have completed $250 million through a share repurchase agreement. We believe this program provides us financial flexibility to continue to pursue opportunistic higher value-added strategic investments while appropriately managing our balance sheet. Now, let's turn to slide 49 to discuss 2007 earnings. Fourth quarter GAAP earnings were $1.42 per share. After special items, our fourth quarter adjusted earnings per share of $1.48 was well within our guidance range of $1.35 to $1.55 per share. For the full year, GAAP earnings were $4.60 per share. Let me walk you through the adjustments to GAAP for the full-year 2007. We had a $0.90 loss related to special items driven primarily by a $0.07 charge reported in the second quarter associated with the decision not to pursue development of a wind investment in Western Maryland. Synfuel earnings per share were a $0.02 loss for the year, driven by an increase in tax credit phase out due to the higher oil prices. We had a $0.01 gain on economic non-qualifying hedges associated with gas storage, which we adjust out of GAAP earnings. Lastly, we had offsetting $0.05 adjustments at the Merchant and BGE, which came from the recently passed increase in the Maryland State income tax rate. This tax change required us to adjust our deferred tax assets and liabilities, which we recorded in the fourth quarter. Overall, our adjusted full year earnings of $4.60 per share were in the upper end of the guidance range of $4.45 to $4.65 per share, which we revised upward at the end of the third quarter. Turning to slide 50, now let's look at operating results by segment compared to the fourth quarter of 2006. The Merchant segment was up $0.39 per share, driven by several factors. Wholesale Competitive supply was up $0.18 per share due to the higher backlog and new business realization. Our Competitive Supply businesses, NewEnergy Electric and NewEnergy Gas, were up $0.10 per share. NewEnergy Electric's performance was up $0.04 per share, continuing the recent trend of strong realized margins. NewEnergy Gas was up $0.06 per share as we saw the reversal of mark-to-market losses recorded in prior periods. Generation was up $0.07 per share, driven primarily by the absence of the Ginna refueling outage in the fourth quarter of 2006. We had lower interest expense due to a larger cash balance and higher short-term interest rates combined with share accretion, which increased earnings by $0.06 per share. There were a number of smaller items that net to a negative $0.02 per share. BGE's results were down $0.01 per share versus last year, driven by credit to residential customers required by Maryland Senate Bill 1 and higher operating costs, partially offset by favorable weather and higher demand response and transmission revenues. Our other non-regulated business segment was up $0.02 per share. Overall, adjusted earnings were up $0.40 to $1.48 per share on a quarterly basis, in line with our expectations. Turning to slide 51, for the full-year 2007, adjusted earnings were $4.60 per share, up $0.99 or 27% over last year, in the upper end of our revised guidance range. The Merchant segment was up $1.09 per share on the plus side. Generation was higher at $0.90 per share, primarily driven by the roll-off of below market hedges; the impact of the Ginna upgrade, which was completed in the fourth quarter of 2006; and fewer planned outage days. These were partially offset by the end of the competitive transition charge, collections, inflation, and higher operating costs. Net interest expense was $0.36 per share favorable due to higher average cash balances combined with higher short-term interest rates, partially offset by $0.02 of dilution for the full year. Our Retail Competitive Supply businesses, NewEnergy Electric and NewEnergy Gas, were up $0.02 per share. NewEnergy Electric's performance was up $0.27 per share, primarily due to higher realized rates. NewEnergy Gas was down $0.25 per share due to mark-to-market losses on hedges of accrual positions and higher costs associated with operational issues that we have identified and remediated, as Tom discussed earlier. Wholesale Competitive Supply was up $0.01 per share due to higher backlog realization, partially offset by lower new business following an exceptional year in 2006. On the negative side, the loss of earnings from the gas plants sold in December 2006 resulted in a negative $0.13 per share variance. There were a number of other small items that net to a negative $0.05 per share. BGE's earnings were down $0.13 per share compared to 2006, primarily driven by the credits to residential customers required by Maryland Senate Bill 1 and higher operating costs, partially offset by customer growth and electricity usage, slightly favorable weather, and higher demand response and transmission revenues. Turning to slide 52, we will now discuss Constellation's 2008 forecast results starting on slide 53. As Tom described in his section, further integration of the Merchant segment will allow us to provide a refined and simplified framework for you to understand and value our operations. Going forward, the Merchant results will be described along the three lines of business activities that Tom referenced, Generation, Customer Supply, and Global Commodities. For 2008, we expect continued strong earnings growth of 14% to 25% over our strong 2007 results. I will discuss the specific earnings drivers in a few minutes. As Mayo mentioned, 2008 will also see a continuation of an aggressive capital investment program to meet environmental regulatory requirements, to expand our generation capacity and improve reliability, as well as to invest in other growth initiatives, which will continue to build a solid foundation for long-term earnings growth. Moving to slide 54, as Mayo and Tom discussed, we are realigning the merchant activities to capture operating synergies and drive long-term growth. As part of this process, we are reviving our reporting framework to provide better visibility into our operating results. On this slide, we provide you with a high-level mapping of our prior reporting framework to the new integrated Merchant reporting framework that Tom described. Our Mid-Atlantic fleet, plants with power purchase agreements, and qualifying facilities have been collapsed into generation, which now includes all of our fossil and nuclear plans in one bucket. Customer Supply comprises NewEnergy, which serves retail gas and electric customers and the power-load serving portion of Wholesale Competitive supply. Remaining businesses in Wholesale Competitive supply including our portfolio management and trading operations, the upstream gas and coal logistics businesses have been broken out and grouped into our global commodities group. Turning to slide 55, on the left we provide a breakdown of Merchant EBIT by component. We also summarize the modeling information we expect to provide for the components of the Merchant segment. The details can be found in Tom's section and in the additional modeling section at the end of this presentation. For the Generation activities, which provides half of the total Merchant EBIT, we plan to provide unhedged EBITDA, the value of the hedges against our Generation assets and the impact of hedging on EBIT. Given the high baseload profile of our Generation fleet, this information should provide significant insight into the hedge profile of our generating assets. We are providing a range of operational metrics for Customer Supply, including backlog for existing business, annual gross margin targets, and annual EBIT forecast, and new business margins. Finally, we show several performance metrics for Global Commodities, annual gross margin targets, the mark-to-market and total portfolio value at risk, and the existing backlog of our Structure Products within Global Commodities. We believe the combination and the additional information we have provided related to the various business activities within our integrated Merchant segment, and these specific metrics will help you better model and value the Merchant segment. Turning to slide 56, for 2008 we are reiterating our guidance range of $5.25 to $5.75 per share, which represents 14% to 25% growth over a very successful 2007. We remain confident that we will be in the mid to upper end of the range for 2008. Our forecast for 2008 shows that we expect the Merchant segment to be up 21% to 34% and BGE to earn between $0.65 and $0.75 per share, down 5% from 2007. Turning to slide 57, we’ll discuss the specific earnings drivers. Overall, we expect our integrated Merchant segment to be up $0.98 per share while BGE and other non-regulated are projected to be $0.08 per share lower in 2008. This slide walks you through the factors that contribute to our 2008 earnings growth versus 2007. Looking at the integrated Merchant, Generation results are expected to increase by $0.73 in 2008, driven primarily by the continued roll-off of lower priced hedges and higher energy and capacity prices. At Global Commodities, we expect earnings to be favorable $0.67 due to significantly higher backlog, which will be partially offset by lower new business in 2008 following a strong 2007. We expect Customer Supply to be down $0.18 per share year-over-year, reflecting the more competitive market conditions that Tom discussed. This is reflected in lower wholesale power backlog going into 2008 as compared to 2007 and lower retail power margins forecast for 2008. We experienced retail power margins in 2007 of $5.39 per megawatt hour and we are projecting margins of $3.80 per megawatt hour in 2008. We expect this to be partially offset by higher earnings from retail gas as we return to normal operations after addressing the operational issues that impacted the business in 2007. Other Merchant items total an unfavorable $0.13 per share and include higher interest, taxes, and other costs, partially offset by share accretion following a November 2007 share buyback. We expect BGE's earnings to be down $0.2, primarily due to higher operating costs and higher interest expense partially offset by higher revenue due to customer growth and higher translation and demand response revenues. In 2008, BGE implemented decoupling for electric distribution, which has similar mechanics as the gas decoupling program that has been in place since 1998. This will result in more stable revenues for the distribution business, normalizing out weather variations and use for customer that may arise from our energy conservation programs to residential and small commercial customers. Lastly, while we expect to be... to file a combined electric and gas rate case in 2008, keep in mind that it will not impact earnings until 2009. The other non-regulated businesses are expected to be down in 2008, primarily due to lower planned earnings at Constellation Energy projects and services as well as the absence of tax credits in 2007. Now, turning to slide 58, this slide shows the capital spending projections in our business plan for 2008 and 2009. As highlighted by the slide, we are projecting an increase in 2008 capital spending of $742 million from the projection we provided you last year. This increase is primarily driven by several factors, which I will discuss in more detail on the next couple of slides. First, a shift in the timing of capital expenditures on our environmental programs from 2007 to 2008 and 2009, increased expenditures related to expanding our generation capacity and improving plant reliability that Tom discussed earlier, increased investment in BGE's infrastructure for reliability and customer growth and conservation programs, and finally the inclusion of $385 million of opportunistic growth capital. In line with historical capital spending decisions, we take a strong risk management approach to capital investment. Therefore, as we identify and assess these opportunities, deployment of capital may deviate from what is currently planned. To the extent we do not see attractive growth opportunities, capital may instead be used to enhance shareholders return in other ways such as the share repurchase program. Let's turn to slide 59 for a detailed view of Merchant spending. First, in the Merchant segment, major environmental projects relating to the Maryland Healthy Air Act comprise a large portion of capital spend in 2008 and 2009 totaling $548 million and $335 million respectively. Related to our prior plan, capital forecasted to be spent in 2007 has now been pushed into 2008 and 2009. This is primarily due to timing on the Brandon Shores and Keystone's scrubber projects. While the timing of the capital spending has changed, overall the projects remain on schedule, with total capital spend consistent with the previous plan. Our planned maintenance capital spend of $385 million for generation and other merchant projects primarily include asset replacement and additional investments to maintain reliability. We expect to invest $354 million of capital to grow and expand our existing business activities, comprised primarily of investment in existing upstream gas properties, fleet reliability improvements, and adding new generation capacity. We have also included $385 million in our capital budget to invest in new growth opportunities similar to investments we have made in upstream gas, Merchant portfolio acquisitions, or other strategic opportunities. Lastly, as market prices for nuclear fuel have risen substantially, our total spend grows from 2007 to 2009. Our forecast for 2008 nuclear fuel has risen by about $50 million since last year due to these market conditions. Turning to slide 60 to review BGE's capital program. In 2007, the utilities spent $402 million of capital, primarily to support maintenance of our electric and gas distribution systems and investment in the transmission system. For 2008 and 2009, BGE is planning to spend $493 million and $562 million respectively. These increases are driven by demand response and conservation initiatives, and infrastructure investments such as replacing and upgrading substation equipment, running new feeders to accomplish growth or accommodate growth in the service territory, and continued investment in the transmission system to add capacity to improve import capability into BGE's service territory. I should point out that the implementation costs for BGE's potential advanced metering initiative are not included in this plan. We are currently planning to roll out a pilot program later this year, and depending on the outcome we could be in a position to deploy $80 million to $100 million annually to this program over the next several years, assuming appropriate rate treatment by the Public Service Commission. Our investment in BGE's infrastructure to support customer growth and increase liability will necessitate BGE filing a rate case in 2008 and subsequent rate case filings thereafter to support the higher levels of capital. That exact timing of subsequent rate case filings will, of course, depend on the outcome of the 2008 rate case as well as other factors impacting BGE's returns. Turning to page 61, bringing the capital and earnings fixture together, in 2008 we expect operating cash flow to be a use of approximately $400 million. As you can readily see from this chart and heard in our prior discussion on capital spending, the $2.3 billion of capital and investments is the main driver of the negative operating cash flow. While we have a substantial cash balance at year-end 2007, you may see us fund some of this capital spending in the debt markets to appropriately manage our capital structure and to maintain financial flexibility. Net cash flow will be negative $529 million, which includes $337 million of dividends. Let me spend a minute on dividend policy. As you know, we announced this morning a 10% increase in the dividend, from $1.74 to $1.91 per share. This represents the fifth year in a row that we have increased the dividend by at least 10%. Similar to the past two years, we did not grow the dividend in line with earnings growth, which would have been a 27% increase from 2006 to 2007. The 10% growth rate is very robust for a company with our growth prospects, and the resulting payout ratio of 34% is appropriate from where our business mix has evolved to a higher percentage of Merchant earnings and less utility earnings. Further, as highlighted by our capital expenditures plan, we continue to see many opportunities to invest in the business at appropriate risk-adjusted returns. Add our previously announced $1 billion share repurchase program into the mix as another option to increase shareholder value and return capital to shareholders, we believe that a 10% dividend increase provides the right balance between dividends and strong business growth. You should expect that we will continue to evaluate these trade-offs, dividend growth, investment in the business, and share repurchases in the future. Turning to slide 62, the balance sheet and resulting credit metrics continue to be strong. Net debt to total capital at the end of 2007 was 36%. This was slightly higher than the 35% at year-end 2006, which was bolstered by the large cash balance due to the proceeds from the gas plant sales at the end of the year. The debt component was relatively flat year-over-year. We used $600 million of the proceeds from the plant sales to pay down a CEG maturity in April 2007. However, since we included the BGE rate securitization debt in the reported total debt balance, you don't see the paydown of the $600 million. Net debt to total capital will increase nominally in 2008 as we continue to invest in the business for Merchant growth, environmental spending, and BGE reliability as discussed previously. As we have mentioned in prior presentations, we primarily focus on the FFO to debt ratio, which is the most important ratio for the rating agencies. In 2006, and for a part of 2007, the BGE deferrals were a drag on FFO. With the deferrals over, we see a significant increase of at least 10 percentage point in the FFO debt metrics. When the rating agencies looked at this metric, they increase the amount of debt by imputing debt from power purchase agreements, pension obligations, training activities, and other comparable activities. They also adjust funds from operations for imputed interest. As a result, they arrive at a much different ratio. Looking at 2008, we estimate that Standard & Poor’s would calculate FFO to debt in the 24% to 28% range versus our forecast of 41% to 45%. With our solid balance sheet and credit metrics, we will continue to evaluate additional share repurchases under the Board authorized $1 billion share repurchase program. We have already executed $250 million of the program and retired approximately 2.5 million shares. This year, we will continue to look opportunistically at additional share repurchases while maintaining our ability to take advantage of and make strategic investments in the business. Turning to slide 63, before I move on to the outlook beyond 2008 I want to discuss quarterly guidance and rollout a modified approach to discussing our outlook within the year. As highlighted by this chart, there could be a significant range of earnings within each quarter, which we believe does not make establishing quarterly guidance a useful in gauging the performance of the business. A combination of an increasing mix of our business results coming from our integrated Merchant activities and limitations associated with applying hedge accounting under FAS 133 introduces the potential for even more variabilities in quarterly results. Given these facts, we feel it is more important to focus investors on full-year projections and long-term earnings prospects than our quarterly results. Turning to slide 64, as a result consistent with almost all other integrated energy companies, we have chosen to eliminate specifically quarterly earnings guidance and replace it with other operating and financial metrics. We will continue to establish and provide annual earnings per share guidance as well as additional information to help you model our business. So let me walk you through our approach. We are providing a BGE earnings per share range, which we expect to be $0.33 to $0.38 in the first quarter of 2008. For Generation, we're providing hedged EBITDA forecast for the prior [ph] quarter. For the quarter, we expect to realize hedged EBITDA of $247 million, which is $29 million higher than the first quarter of 2007. The final metric we are providing is customer supply backlog, which is expected to be $57 million, consistent with the first quarter of 2007. Combining this quarterly information with the expanded view of the integrated Merchant that Tom reviewed with you provides significant detail. While we are not providing quarterly information on Global Commodities, as this is the most volatile and difficult to project, we have provided more detailed annual information, which should help you model the company. Turning to slide 65, now let's take a look at the longer-term outlook starting with slide 66. Looking beyond 2008, we are forecasting continued strong growth. In August, we told you that we are expecting growth in 2009 of greater than 10%. We are now confident that in 2009, we can achieve 15% to 20% growth over 2008. As Mayo said, once we see how 2008 develops we should be in a position to convert this percentage range for 2009 into a dollar-based range later this year. Over the five-year planning period, we currently project a compound average growth rate of greater than 10%, which may not be linear. Let's turn to slide 67 to wrap up the financial section. In closing, let me highlight a couple of points. First over the past several years, we have made significant improvements in our return on invested capital, which is evidenced by our strong earnings growth. Our disciplined approach to managing capital has driven improved performance and ultimately, total shareholder return. We employ vigorous analysis to ensure we continue to be good stewards of your capital by investing in opportunities that exceed their appropriate risk adjusted cost-to-capital. The ability we have demonstrated in driving appropriate risk-adjusted returns will continue to serve us well as we increasingly invest in the business to drive future growth to increase shareholder value. Now, I will turn the podium back over to Mayo for concluding remarks. Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Thanks, John. So throughout the presentation you’ve heard me and Tom and Mike and John describe the outlook for Constellation. Before we open up for questions, let me take a moment to summarize the key themes that make up the investment basis for the company. First, our highly hedged Generation fleet provides clear and substantial earnings growth. Through 2009, we are projecting compound annual earnings growth of 15% to 22% following on 2006 increase of 27%. Second, our business is supported by high quality assets in high value markets. Our low cost baseload, nuclear and coal fleet is located in PJM and New York where the market dynamics continue to point to the need for new generation and where we are positioned to deliver. Additionally, with greenhouse gas regulation on the horizon, our low emitting fleet is well positioned to benefit from a constraint carbon environment. Third, we see opportunities to deploy capital that will crate potential for future earnings growth. As Tom and John described, we see a clear path for many of our investments. We are also laying the foundation in another areas like advanced metering or new nuclear that could lead to significant investment and sustained earnings growth. Our disciplined approach to investing capital and reputation for being good stewards of capital should hold us in good stead as we evaluate these opportunities. And finally, this management team has a superior track record of driving significant earnings growth and delivering substantial total shareholder return. As you've seen throughout the presentation, we are poised to continue this in the future. So this concludes our prepared remarks. We'd now like to open it up for questions we have. Question and Answer

[Operator Instructions]. One moment please.

Basically, we calculate that your nine-month cash flow is roughly $150 million less than your nine-month EBITDA, and that includes about $52 million of non-cash gains from the sale of CEP stock and about $104 million of lower depreciation recorded on your cash flow statements. Why is the cash flow depreciation lower than your income statement depreciation? And should we continue to look for non-cash EBITDA adjustments in your forecast numbers? Kevin W. Hadlock - Vice President of Investor Relations: Andrew Good, CFO in our Merchant activities. Andrew L. Good - Chief Financial Officer, Constellation Energy Commodities Group: One of the differences that we encounter in the presentation of cash flows versus depreciation has to deal with how emission allowances that we hand into the EPA for burn of the fleet. So if you are trying to look at what's going on in the inventory and you look at the actual decreases that would show up in say working capital, when we hand in it shows up as the variation or change in the inventory. It won't show up in a... use on the cash flow statement. So one of the drivers that we can try to point that up more clearly, possibly in additional math modeling in the future. That tends to be the biggest variation there. John R. Collins - Executive Vice President and Chief Financial Officer: We can actually sit down with you after just to walk through that detail type of questions. Yes, they would continue, but I mean, I don't... I'm not sure that's material to the overall cash flow picture of the company.

Question for John. I noticed that last year you gave... there was sum-of-the-parts valuation slide in your presentation. This year you don't have a sum-of-the-parts value slide. So I went to page 18 and I looked at the unhedged EBITDA and PV of hedged value and I looked back on page 85 and I got the EBITDA for the other components and I reran your slide using the midpoint of the ranges. I’m coming out at around $150 to $160 a share. Is that... am I doing that correctly? Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Math work. John R. Collins - Executive Vice President and Chief Financial Officer: I haven't done the math like you did, but I think if you do the sum-of-the-parts evaluation, I believe last year this time on the Analyst Day we showed you somewhere in the neighborhood of $96 to about a $145, sum-of-the-parts valuation if you did the math properly. I think if you redid the math this time, you will see the number is slightly higher than that range, so your number is probably not outside the relative range that you can get to.

My other question was just on EDF. Have they started buying your stock and--? John R. Collins - Executive Vice President and Chief Financial Officer: We actually cannot comment on whether EDF has actually started buying our stock or not. That is something that you'd actually have to ask EDF.

Hi. It's Andy Levy from [inaudible]. Just two quick questions, accounting related. How much of your EBITDA is non-cash? As I noticed, you have about $10 billion liability on your balance sheet called unamortized energy liabilities. I believe that is in [inaudible] to debt, but you don't seem to have this on your adjusted debt figures. Can you explain why we should not count this as debt… like a debt-the instrument? And then in addition, I noticed in 2007 it did actually turn around, but it appears that the last three years, '04, '05, '06, your net income has been increasing while your cash from operations has been declining. So I was just wondering if you could reconcile it difference for us from that. Kevin W. Hadlock - Vice President of Investor Relations: Yes, Andrew will handle it because it’s primarily about the Merchant when you are talking about the derivatives. Andrew L. Good - Chief Financial Officer, Constellation Energy Commodities Group: Well, I can take the first part, the energy… the unamortized energy is I believe we disclosed in 2006 that we moved the contract out of a cash flow hedging. So formally it's shown up in portfolio risk management, moved it over, we declared it as a normal purchase, normal sale. We had to keep track of it on the balance sheet. So easiest way I can describe it for you is think of that category as similar how we talked about our cash flow hedging for the mark-to-market asset liability in our portfolio risk management asset liability, which is why actually it'll show up in S&P as equivalent to how they treat that behavior. The broader question though--. John R. Collins - Executive Vice President and Chief Financial Officer: Can you state the second part of the question again, I'm sorry?

Second part of the EBITDA question or the cash flow question? John R. Collins - Executive Vice President and Chief Financial Officer: The three-year cash flow.

Looking at 2004, 2005, 2006 cash from operations on a GAAP basis, I think we are $1.86 billion, 627 and 523, and then it actually climbed to 928 in 2007. So they were declining, but your net income went from 539 to 623 to 936, I don't have the 2007 number. So I was just curious, if you could reconcile the differences? John R. Collins - Executive Vice President and Chief Financial Officer: We can reconcile that with you after this in fact. So if you want to get with us after the Q&A, Kevin and we'll sit down with you and reconcile that for you. Kevin W. Hadlock - Vice President of Investor Relations: Yes, up front here.

I wanted to ask you, on 586, with your asset dispositions and contract restructuring, just if you could out a break out a little bit for us in '07, what sort of happened there because I recall you guys getting a little bit more cash from some of these contract purchases that you guys got? And just what are you actually seeing in 2008 in terms of that? And how do you break out the constituents associated with that? That's one question that I sort of was just wondering if you could elaborate on. The second question I have is really sort of back to Maryland and what you're seeing there with respect to the IRP proposals that the Commission seems to supportive of. I don't know what they are going to actually do, but their report seems to be very supportive of. How do you see that impacting the potential for getting to new-build economics in wholesale market in Maryland, I mean just in general if you could sort of comment on that? I had seen some of your comments in some of your filings. I was just wondering if you could just elaborate a little bit on that and what you see… potentially, what we should be expecting from your interaction with the Commission in the next few months? Kevin W. Hadlock - Vice President of Investor Relations: Why don't you start with question one? Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Well, really what's in the light are two things, number one is any asset dispositions that we would be planning to undertake and then the amortization of contract that has been restructured and also part of when we have entered into PPAs and we get cash for PPAs that those cash has been amortized over. So that's really what's driving in '07. In '08, we have planned some divestures in the portfolio, which basically would make that a positive number in '08. So that's really what's your seeing within the plan.

What I'm wondering is why is the… $30 million seems to be a lot lower than the amount of money that your guys got… I think from just the Progress Energy contracts that they... that financing? I’m just wondering how… that’s now just $30 million? John R. Collins - Executive Vice President and Chief Financial Officer: Can we just… we’ll go through the accounting of that after because it get a little technical and I’m not sure that we want to. Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: On the second question, I'll start a response and ask Tom to elaborate on it. But I think it's evident to most people that the construction of the capacity markets in PJM has been received by the participants in the market well as creating the construct to provide market signals for us to make investment decisions and we are headed down that path. Tom explained some of the details associated with where we might build, where we have filed for with PJM, and you are obviously well aware of our interest in new nuclear development over a longer term. Given that a lot of this has really just happened in the last year as is to be expected, the political side of the equation is impatient with capacity markets and the evolution of those capacity markets, because it doesn't provide the instant gratification associated with lowering rate. So there is clearly a philosophical debate here going on in the political environment about whether we all have enough patience to let the market work. Now, we are, as a company, tremendous advocates of the competitive markets as everybody who has followed our company for years knows. We believe it's working. We believe there are a lot of specific signals that it's working. On the other hand, the way in which market pricing is evolving at the moment, it doesn't necessarily give the absolute clear signal that it's time to build. And so, as we are making plans, creating the optionality for plans of different types, obviously the decisions we make are going to be contingent upon what we think the return is going to be, that's going to be contingent on where we think gas is and where pricing is and so forth. So there are a lot of things that will evolve in time, but we believe that it's evolving in the correct fashion, sending the right kind of information to us as a participant in the market. And Tom outlined some of those plans. So... but nonetheless, it's… I think we all have to expect that the impatience of the political side is very much at the forefront and you see it with the Maryland PSC and their examination of how they think the wholesale markets are responding to what they need, which is lower prices now. Thomas V. Brooks - President, Constellation Energy Resources; and EVP, Constellation Energy Group: I guess, just to add slightly just in terms of the market dynamics, of course in restructured markets, sort of the concept of deregulation is a bit of a misnomer in the sense that these electricity markets are very heavily regulated and the form of regulation on energy prices comes in the form of offer price caps, market dispatch rules, and real-time price mitigation. The impact of these on energy prices is actually the cause to effectively reduce energy prices in times of actual scarcity. So if you compare spot price volatility, let's say, in 1999 to spot price volatility in 2005 at a sort of similar level of summer time heat, what you'll see is in 2005 much lower spot price volatility than '99 in spite of much higher natural gas prices. So the impact of this form of market regulation is pretty clear and depressing energy prices. As a result, of course, many ISOs created these new capacity market programs in effect to replace the missing revenue caused by the energy price mitigation efforts. And you take the example of PJM, certainly the new RPM capacity program does a great deal to, in effect, replace the missing money and we think we have seen significant signs of companies starting to invest not just in new built Greenfield power plants, but also investments to increase the reliability of existing power plants, extend the life of existing power plants, or add capacity to existing sites. So we think, in general, this is having the intended effect. In terms of the aggregate market dynamics, in most areas in PJM, the total revenue that one can earn, both energy and capacity, doesn't fully cover the cost of new combined cycles today. But given the outlook for increasing demand, we think it's likely that over time that certainly will be the case, therefore some of our efforts to develop new capacity. In terms of the question, Paul, of what will be, sort of, the impact of IRP like considerations by the Public Service Commission, I think in general, separating out from some of the political rhetoric, we think it is completely appropriate for the Maryland Commission to broadly consider energy to supply in the state. And one could imagine a set of steps taken by a commission that might make the investment environment less attractive, but we haven't exactly seen indications of that. So I think our approach and probably the approach of others is to develop the option to invest and sort of watch as the climate evolves. Kevin W. Hadlock - Vice President of Investor Relations: We want to go to the phone. We have a question on the phone.

Dan Eggers from Credit Suisse, your line is open. Daniel Eggers - Credit Suisse: Good morning. Mike, I was wondering if you could give us an update on your thinking as far as new-build costs for the nuclear project, if you have updated your numbers kind of in the '05 [inaudible] yet? Michael J. Wallace - President and CEO, Constellation Energy Nuclear; and EVP, Constellation Energy Group: Sure. We did a cost estimating process about two years ago when we first began working with Areva, and importantly since we formed the partnership joint venture with Electricite de France and closed that in August, we are now importing the data from the Flamanville project, which the think to be most appropriate because that's what we intend to replicate as a baseline plant for developing our cost estimate here. All that information flows into the post model that our Bechtel partner uses. Today, it's well in excess of 20,000 line items, and we're evaluating that and we would expect over the next two months to bring that to closure so that we have an update with where those cost are. And the numbers that we've used in the past publicly are $2,400 a kilovolt levelized over four units in just under 3,000 a kilowatt for one unit, those are two-year-old numbers. We expect those are going to go up slightly, but we also believe that the experiences in France are going to mitigate where they may go. So in the next two months, we will have an outcome that we can talk about. In general, as we look at all the factors, we believe the costs would seem to be well within a range of reasonableness to support an economic decision, but we haven't finalized our review yet. Daniel Eggers - Credit Suisse: And I guess either Mayo or Tom, could you just share the thought process behind how you might consider going to Nine Mile Point, which is the next expansion project [inaudible] depending on kind of New York market developments and probably more importantly what's happening in PJM and Maryland? Michael J. Wallace - President and CEO, Constellation Energy Nuclear; and EVP, Constellation Energy Group: This is Mike Wallace. Let me take the first part of that perhaps and that is very much in the beginning, three years ago, as we started down this path, we wanted to make sure we always had options, should we not be able to resolve uncertainties on any one of a number of variables. One of those variables, of course, is always the ability to permit and license any given site. So while Calvert was our choice for the reference plant, we early on established Nine Mile Point as our fallback. So we have been pursuing all of the information permits required and actually, we've gathered the site data in Nine Mile Point in support of our license applications. Intentionally, Nine Mile has always been several months behind Calvert Cliffs in a sequence, that's where it is today, but it's very much an alternative for U.S. EPR.

Two quick questions. I sensed from the Q&A that there is some concern over the delta between net income and cash flow because a lot of your business is in structured products. Maybe I can ask that question a little bit differently. When you look at the half-life of some of these deals that you enter into, which you have to either... which you have to mark-to-market and not use accrual accounting for, what's the general time frame over which the cash actually flows into the company? Is it a two-year half-life, one-year half-life, five-year half-life? I mean, how long do you have to wait for these cash flows from these transactions to flow in on average? Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Well, let me start and then Andrew could chime in. Two things I guess, Greg, when you look at it. Number one, you have obviously mark-to-market earnings from your portfolio management and trading results. And generally speaking, those probably are two-year type time horizons, but you also have a portfolio that's always being managed and entered into new transactions. On the structured products, many of those which are not necessarily mark-to-market, but if you are talking about like PPAs that we enter into, and this gets into a little bit of the accounting, is that in effect that what you have to do is you have to amortize that cash into income over a certain period of time over the life of those PPAs relative to the economic value of where it falls. And then, what we've done on the line item on the asset dispositions and restructuring, that's kind of where the cash comes in, but then it's also where you net out the amortization, because that is non-cash income. So you don't necessarily see the income associated with those. The cash is really down that asset restructuring line. So if you were to look in the additional modeling, say back in 2006, the 1.75 billion you have there, basically that's large cash inflows coming from asset restructurings or contract PPAs or whatever you want to do and then over time, as we get… that has to be amortized into income, which doesn't have cash associated with it. So that's one of the big deltas that you are seeing driving that. And so, if you were to look at '07, you see that $30 million. While we did the Progress transaction, which did bring in cash, we're amortizing existing type of contracts similar to that that actually have to get amortized out, and that's really what's driving it here. Andrew, I don't know if you want to add anything? Andrew L. Good - Chief Financial Officer, Constellation Energy Commodities Group: Just for clarification, '07 would also have our--. Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Gas plant sale. Andrew L. Good - Chief Financial Officer, Constellation Energy Commodities Group: '06 has had gas plant sale, '07 has our acquisition of the Cornerstone as we explained in our retail gas presentation. So there is a variety of things going both ways. If I can just say, maybe you think about it three ways, let's – actually when you get structured products backwards, Greg. So we get cash in upfront and then… so we get this large cash infusion and we get paid-out because the underlying tolls that we are acquiring our underwater. So on a go-forward, we pay cash back out. Over time we believe we can use that profitable margins. And so with the cash in, we've already declared to you the cash upfront, we can go back and show that to you, paid in cash over time. On our energy investment side, so as we’ve talked about… we invest in assets and then we earn on those assets over time. That would be the traditional cash out upfront and we'll get back cash in over time. And I see, if you look at our '08 earnings for example that Tom showed you on the energy investments in our structured product, you’ll see how we are getting a return on net cash flow. And then, we’ve got the mark-to-market where we will show you the earnings and we actually disclosed you in our Ks and Qs kind of the average life and as John indicated by the two to three-year contract utilization, if you will. So these aren’t [ph] 20-year contracts.

Okay. Second question. I just looked in the appendix at the earned return for the electric and gas distribution into at BGE at 6.7%, just did a rough math assuming a 50% equity ratio, and it looks like if you were to earning 10, which would be a little bit lower than the average authorized ROE in the last 12 months, that you are under-earning by about $0.25 a share. So if you are going to be systematically under-earning in this business, why would you continue to want to own it and invest as much capital as you are investing in it? And then, as a follow-on question, why in the world would you commit billions of dollars to invest in a nuclear plant in a state that is using 20-20 hindsight on deals that you didn't do ten years ago? Mayo A. Shattuck, III - Chairman of the Board, President and Chief Executive Officer: Two good questions, I'll start and have others chime in, but I'd... BGE is under-earning. I think I understand the impact of the last couple of years on… principally why they are under-earning, but it is also a function of the fact that we've had no rate case really since '93, of course the '99 settlement agreement lowered overall rates by 6.5%. So it has been many, many years. We have, I think in our I guess our last call, given the indication that we will file a rate case this year. So that will be obviously a movement to get things back in the right direction. And we will… since it's been many, many years, it's sort of hard to predict what the outcome [inaudible] be, but we would certainly hope to get a fair return on the investments being made there. And I do things that the state has a considerable incentive to make sure that the utility gets a fair return since our plans for capital expenditure, particularly on the efficiency and conservation measures, are quite significant and they seem to be very receptive to those programs. So my sense is that we’ll have a fair debate about that issue and that the overall profitability of the utility will be restored over time. The issue of… sort of more macro issue is how stormy is the state with respect to making investment decisions, and I think that you can tell from our public comments in our release that we perceive it as being pretty stormy right now. It is hard to put it all in context, but I'll try just for a moment to review the quick history, which is to say that we all know what happened at the end of the rate freeze. After for all these years, rates needed to go up. The hurricanes came and costs went way up, and at that time we announced that we are going to do a merger with FPL. As a consequence, the state legislature decided to pass a law that in effect extracted $387 million from us. But that in effect was a… I think a perception on their part that there was value to be extracted in the merger, given that they didn't particularly trust the public service commission at that time that they needed to intervene and preemptively extract $386 million in the context of that merger agreement. They passed a law to that effect, but the heightened anxiety about rates proceeded to lead to the conclusion that they needed to fire the PSC anyway. So they went ahead and fired the Public Service Commission. That put us in a very unstable period of time, that again as everyone in this room knows lead then to the termination of the merger, given that we couldn't lead… we couldn't have a level of confidence associated with getting the transaction completed. So that is why we went into a standstill agreement on the unconstitutional taking of the 386 million. We really had a very hopeful view that a new Public Service Commission, once installed, once educated would actually work through these issues and that there would be some manner in which way to come to terms with the takings of that law. Now, I think as you can see from our press release I think it's our view that the... really given all the things that need to happen in Maryland from a capacity standpoint and the kind of decisions that we have to make from investment standpoint, we really want to get the debate back into a neutral party, so that it can be resolved. And the indication from the most recent Public Service Commission reports, which were very prejudicial, very unfair, very unfounded in its content, and I think for those of you who have looked at, it's hard not to conclude that this is a prosecutor judge and jury all in… one in its tone. And as a consequence, I think that we felt very strongly that we needed to respond to that to protect the interest of our shareholders and our position, and probably even more importantly to protect the interest of Maryland rate payers and longer-term the creation of more capacity in Maryland. We need a stable environment, and without getting it into the hands of a neutral party where it's already… this issue of the '99 settlement has already been adjudicated twice and confirmed is that we get it back into federal courts for the third time. And so for the third time, we'll have the judicial system say that a settlement was a settlement. And I trust that somewhere in that whole process, it will be determined that all of the people in '99 who were involved in this whole decision were not as stupid as the report would seem to imply, that some of the more astounding accusations that people involved in the '99 settlement didn't know the difference between net present value and future value, didn't know the difference between pretax and after-tax, all such fundamental tenants of the regulatory process. I just... I think that we need to get to a place with a sense of reason and neutrality, and it turns out that we have that opportunity, we believe, to accelerate the resolution, so that for the third time we get our position confirmed and we move on. We want to... as you know, want to be very constructive in the process of getting to the right answer here, because there are a lot of very big decisions to be made. Someone logically asked the question, would you build Calvert before Nine Mile? Well, I think this company is investing between $2 billion and $3 billion a year in these forward years. These are big, big numbers. You add nuclear on to that equation, it is going to be even more important that we have the kind of stability to make these decisions. So I think that that's... we are hopeful we get through this, and I think we will get through it. It's just that we all understand that things have gotten highly politicized, that rates are high, no one is happy. It’s hard to get anyone to understand that BGE rates are right in the middle of the pack of all the utilities in the mid-Atlantic. In the Northeast, it's a... there is nothing particularly unusual about our circumstances or even Maryland’s reserve capacity for that reason... for that matter. So we will just keep working to get reason into the debate and make sure that we get the right audience. And I am confident that we will get to the right answers. Last question? Yes.

Thanks very much. I was wondering if you could comment on forward heat rates for the next few years in PJM and whether they are consistent with your views on the trend in reserve margin, really where reserve margins are going and if not when and how you see that getting reconciled? And then, secondarily, can you comment on how the recent volatility in coal prices impacts your business model? Thomas V. Brooks - President, Constellation Energy Resources; and EVP, Constellation Energy Group: In terms of heat rates, which I think you mean to serve as a proxity... as a proxy for growing market, scarcity if you will, certainly heat rates [inaudible], heat rates obviously did widen during 2007 considerably. I think as a proxy for scarcity that gets to the point of creating an investment signal, in most areas in PJM, if the... sort of if the incremental investment will need to be in gas-fired capacity by and large, I guess I would argue that in general heat rates are not to a point where new investment gas-fired capacity generally looks attractive. So I think to us that would suggest that something has got to give, presumably prices need to go up. In terms of the impact of recent coal price movement, limited on the... in terms of the impact on the Generation fleet, relatively limited on the front end simply because of our overall hedge... hedging approach relatively long-dated. In terms of the longer-term impact, a bit a bit harder to say, particularly where we're in process for our stations, Crane and Wagner, of broadly considering a variety of environmental compliance alternatives, which could well involve coal switching as a significant element. So in terms of the sort of movement in the Central Appalachian coal market, this may or may not be... as our overall compliance approach evolves, this may or may not be a hugely relevant issue for us. Kevin W. Hadlock - Vice President of Investor Relations: Okay. Well, thank you all very much for coming this morning. We'll be around… the whole management team for a few minutes and we welcome your questions. Thanks again. See you next quarter.