constellation energy Q4 2007 Earnings Presentation 2007 Fourth Quarter

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Constellation Energy2008 Analyst Presentation

January 30, 2008

Kevin Hadlock:

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 the phone, we’re just gathering here in New York, but I would like to thank everyone for joining us here today.

I’m 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 here in New York.

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Forward Looking Statements DisclosureCertain statements made in this presentation are forward-looking statements and may contain words such as “believes,”“anticipates,” “expects,” “intends,” “plans,” and other similar words. We also disclose non-historical information that represents management’s expectations, which are based on numerous assumptions. These statements are not guarantees of future performance and are subject to risks and uncertainties that could cause actual results to be materially different from projectedresults. These risks include, but are not limited to: the timing and extent of changes in commodity prices for energy including coal, natural gas, oil, electricity, nuclear fuel, and emissions allowances; the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted on a transitional basis in those markets; the conditions of the capital markets, interest rates, availability of credit, liquidity and general economic conditions, as well as Constellation Energy’s and BGE’s ability to maintain their current credit ratings; the ability to attract and retain customers in our competitive supply activities and to adequately forecast their energy usage; the effectiveness of Constellation Energy’s and BGE’s risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and other commitments; the liquidity and competitiveness of wholesale markets for energy commodities; uncertainties associated with estimating natural gas reserves, developing properties and extracting gas; operational factors affecting the operations of our generating facilities (including nuclear facilities) and BGE’s transmission and distribution facilities, including catastrophic weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control; theinability of BGE to recover all its costs associated with providing customers service; the effect of weather and general economic and business conditions on energy supply, demand, and prices; regulatory or legislative developments that affect deregulation, transmission or distribution rates, demand for energy, or that would increase costs, including costs related to nuclear power plants, safety, or environmental compliance; the ability of our regulated and non-regulated businesses to comply with complex and/or changing market rules and regulations; the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in applying mark-to-market accounting, such as the ability to obtain market prices and in the absence of verifiable market prices, the appropriateness of models and model impacts (including, but not limited to, extreme contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors); changes in accounting principles or practices; losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets; our ability to successfully identify and complete acquisitions and sales of businesses and assets; and cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities. Giventhese uncertainties, you should not place undue reliance on these forward-looking statements. Please see our periodic reports filed with the SEC for more information on these factors. These forward-looking statements represent estimates and assumptions only as of the date of this presentation, and no duty is undertaken to update them to reflect new information, events or circumstances.

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 www.constellation.com under Investor Relations.

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Use of Non-GAAP Financial MeasuresConstellation Energy presents several non-GAAP financial measures in this presentation in addition to information in accordance with generally accepted accounting principles (GAAP) amounts. This includes measures such as adjusted earnings per share (adjusted EPS), Gross Margin, EBIT, EBITDA, Net Debt to Total Capital, Free Cash Flow, and Net Cash Flows for Debt Payments.

Constellation Energy provides its earnings and annual earnings guidance in terms of adjusted EPS. Adjusted EPS differs from reported GAAP EPS because it excludes the cumulative effects of changes in accounting principles, discontinued operations, special items (which we define as significant items that are not related to our ongoing, underlying business or which distort comparability of results) included in operations, the impact of certain economic, non-qualifying hedges, and synfuel earnings. The mark-to-market impact of economic non-qualifying hedges is significant to reported results, but economically neutral to the company in that offsetting gains or losses on underlying accrual positions will be recognized in the future. Synfuel earnings are excluded due to the potential for oil price volatility to result in a difficult-to-forecast phase-out of tax credits. We present adjusted EPS because we believe that it is appropriate for investors to consider results excluding these items in addition to our results in accordance with GAAP. We believe this measure provides a picture of our results that is comparable among periods since it excludes the impact of items such as workforce reduction costs or gains and losses on the sale of assets, which may recur occasionally, but tend to be irregular as to timing, thereby distorting comparisons between periods. However, investors should note that this non-GAAP measure involves judgment by management (in particular, judgment as to what is classified as a special item or an economic, non-qualifying hedge to be excluded from adjusted earnings). This non-GAAP measure is also used to evaluate management's performance and for compensation purposes. Constellation Energy is unable to reconcile its annual earnings guidance to GAAP earnings per share because we do not predict the future impact of special items, economic, non-qualifying hedges or synfuel earnings due to the difficulty of doing so. The impact of special items, economic, non-qualifying hedges, or synfuel earnings could be material to our operating results computed in accordance with GAAP.

We note that adjusted EPS and the other non-GAAP measures utilized by Constellation Energy are not in accordance with GAAP and should not be viewed as an alternative to GAAP information. A reconciliation of non-GAAP information to GAAP information is included either on the slide where the information appears or on one of the slides in the Non-GAAP Measures section provided at the end of the presentation, along with additional information on why and how Constellation Energy uses this information. Please see the Summary of Non-GAAP Measures included to find the appropriate GAAP reconciliation and its related slide(s). These slides are only intended to be reviewed in conjunction with the oral presentation to which they relate.

On slide 3, you will notice we will use Non-GAAP financial measures in this presentation to help you understand our operating performance.

We’ve attached an Appendix to the charts on the website reconcilingNon-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 will be subject to change as we refine our estimates associated with the components of the Merchant segment.

With that, I’d like to turn the time over to Mayo Shattuck, Chairman, President and CEO of Constellation Energy…

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Agenda

9:05 – 9:10Mayo ShattuckConcluding Remarks

8:35 – 8:45Mike WallaceNew Nuclear

9:10 – 9:30

8:45 – 9:05

8:15 – 8:35

8:00 – 8:15

TimeSpeakerTopic

AllQuestions & Answers

John Collins Financial Overview

Tom BrooksIntegrated Merchant

Mayo ShattuckStrategic Overview

Thank you, Kevin. Good morning, everybody. I’m glad to see that all of New York is not yet shifted out to Arizona. So thank you for coming. And thank you to 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 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 have provided bios for all the executives in attendance. Following the meeting, please introduce yourself to them and ask them any additional questions that you may have.

Let’s begin on slide 5…

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2007 Highlights• Generated adjusted EPS growth of 27%

– Adjusted EPS results of $4.60 toward the top of our upwardly revised guidance of $4.45 to $4.65 per share

• Delivered total shareholder return of 52% in 2007

– Executed $250 million of the $1 billion share repurchase program

– Raised 2008 dividend by 10% to $1.91 per share

• Advanced new nuclear initiative– Formed UniStar Nuclear Energy JV with EDF (up to $625 million

investment by EDF)

– Preparing COLA’s for Calvert Cliffs, Nine Mile Point & partners’ sites

• Enhanced Merchant capabilities

– Built foundation to invest in multi-year generation initiatives

– Completed strategic acquisitions

• Implemented Smart Energy Savers Program at BGE to help customers manage their electricity needs and consumption

– Received approval for Demand Response and Energy Efficiency programs

– Launched Advanced Metering pilot program

2007 Adjusted EPS Growth Rates

27%

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CEG S&P Elec Index S&P 500

2007 Total Shareholder Return

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CEG S&P Elec Index S&P 500See Appendix

This management team is sharply focused on delivering results and, in 2007, we had another outstanding year. We grew earnings by 27 percent and generated adjusted earnings of $4.60 per share. This performance was toward 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 percent in 2007, following the 23 and 35 percent total shareholder returns realized over the last two years. In addition, we announced this morning we will grow our 2008 dividend by 10 percent to $1.91 per share.

In 2007, we made significant progress on our new nuclear initiative. 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 continued 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 received approval 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 drove strong total shareholder return for our investors in 2007. As you’ll see throughout the presentation, we’re poised to continue our success in 2008 and beyond.

Turning to slide 6…

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Commodity Price Increases (2002 to 2007)

• Rapidly rising input prices have increased the cost of electricity

• Constellation is helping customers manage energy costs by investing in generation capacity and conservation solutions

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Prices for commodities have risen sharply in recent years at both the wholesale and retail levels. However, you’ll note that while our 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 manage energy costs in this market environment.

On to slide 7…

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Potential Technology Impact on Emissions

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Source: Electric Power Research Institute, Inc.

In addition to the increases in commodity prices that customers have experienced over the past several years, the market is increasingly focused on the need to stabilize greenhouse gas emissions in the U.S. electric sector. This chart from the Electric Power Research Institute and one that you should be very familiar with, it’s used frequently, illustrates a potential path to slow, stop, then reverse the rate of greenhouse gas emissions. Efficiency programs and 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 the 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 to slide 8…

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Environmental Landscape

• Constellation is meeting the challenge of reducing our operational impact on the environment

• Maryland Healthy Air Act / Clean Power Rule

• Regional Greenhouse Gas Initiative

• Cap and Trade Program

Regulations

2008• $548 million of capital expenditures

planned for major environmental projects

2008 – 2012 • $945 million of total major environmental

capital expenditures planned– Brandon Shores scrubber– Other PJM coal plant

modifications

Constellation Response

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 a federal policy will be implemented to supersede regional initiatives like RGGI and align the U.S. with a global effort to reduce greenhouse gas emissions.


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Response to Demand for Clean EnergyEnvironmentally Focused

and Responsive

• More than 60% of current output sources from low emitting nuclear and hydro sources

• Installing flue gas desulphurization (FGD) scrubber at Brandon Shores

• Providing products to assist customers in meeting conservation and environmental objectives

• Assisting new sources of supply by providing a market or managing risk

• Providing customers with tools to manage energy consumption and cost

Positioned to Adapt to Market Evolution

• Existing fleet is strategically positioned in location and fuel type

• Evaluating potential to build new plants and re-open retired generation capacity in MD

• Pursuing potential deployment of new nuclear fleet

• Managing demand response on behalf of customers

• Ability to leverage large customer base to provide new products

• Active in domestic and international, environmentally-focused energy markets—CO2, SO2, NOX, and low-emissions coal

• Advanced metering and demand-side management with utility customers

Supply –Generation

Demand –Customer Supply, Global Commodities, BGE

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 percent of our megawatt hours coming from low-emitting nuclear and hydro sources. Looking to 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 programs 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 10…

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Maryland Update• Maryland PSC interim report on 1999 stranded cost

settlement is flawed and potentially destabilizing• Constellation press release highlighted errors and

mischaracterizations• Constellation will file a federal court action to enforce

our rights under the 1999 settlement • Constellation will vigorously act to ensure the sanctity

of settlement agreements and contracts

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 and the 1999 Settlement injected a profoundly destabilizing element of uncertainty into the regulatory climate and the energy market place 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 the 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, omissions 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 long-standing settlement. But as everyone here has 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 dwell 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 dollars 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 the method of collecting those dollars and capped the nuclear decommissioning liability that ratepayers face 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 dialogue 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 market place. 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 part of a fair and productive dialogue about how best to improve laws and regulations. But when we see attempts to rewrite history or exert pressure on legitimate agreements, we will act vigorously to protect the interests of our shareholders.


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Maryland Update• Maryland PSC, administration and lawmakers

considering a broad energy agenda – Conservation and efficiency support – Renewable portfolio target expansion – Regional Greenhouse Gas Initiative revenue fund – Greenhouse Gas policy– Balance reliability, affordability and sustainability

Meanwhile, there are some positive policies being offered to thelegislature in regard to conservation and efficiency, and we hope to work with lawmakers and non-governmental organizations to make progress in those 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 imperatives 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. Policy makers must have the wisdom to allowmarket forces to work and resist the temptation to intervene in natural supply and demand economics.

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Era of Growth• Constellation has predictably and consistently delivered on earnings

guidance through a variety of market conditions

– Realized annual total shareholder return of 29% since 2001

• Clear and substantial earnings growth through 2009

– Reaffirming guidance of $5.25 to $5.75 per share for 2008

– Projecting 15% to 22% compound annual growth from 2007 through 2009

• Well positioned to deploy capital for development of market opportunities

– High-quality assets in high value markets

– Market-leading position in power and strong presence in gas and coal markets

– Industry-leading risk management capabilities and disciplined investment approach

– Strong balance sheet

See Appendix

Before I turn the call over to Tom Brooks, let me summarize the investment thesis 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 upper end of this range. This represents 15 to 22 percent 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, high 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 to capture opportunities.

With that, I’d like to turn the podium over to Tom Brooks to discuss the outlook for our Merchant business…

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Merchant Business

Tom BrooksPresident, Constellation Energy Resources

Thanks Mayo. Good morning everyone and thanks for joining us today. I’ll spend the next few minutes discussing our merchant business, starting on slide 14.

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Constellation’s Merchant Business

• 8,700 MW of efficient, low cost generation in high value markets

• Risk manager, market leading trader, and developer of Constellation’s energy investments portfolio

Generation

Global Commodities Group

50% of Merchant EBIT (2008E) 25% of Merchant EBIT (2008E)

25% of Merchant EBIT (2008E)

• Market leading supplier of electricity and natural gas products and services

Customer Supply Group

Note: Included in this section of our presentation is a preliminary view of certain recast historical financial information to provide a basis for comparison to our new 2008 merchant reporting framework.

Constellation’s merchant business is comprised of Generation, our Customer Supply Group, and our Global Commodities Group.

Our nuclear & fossil generation teams operate 8,700 MW of mostlybaseload capacity located in central New York and southeast PJM. Our generation teams focus on maximizing the contribution from our fleet and, increasingly, on developing opportunities for new investment.

Our Customer Supply Group is the market leader in providing electricity and natural gas products to wholesale and retail customers throughout North America.

Our Global Commodities Group is a risk manager, market-leading trader and developer of our structured products and energy investments portfolio.

Turning to Slide 15…

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Agenda

• Generation

• Customer Supply

• Global Commodities

• Summary

Let me now talk about each of these areas in more detail beginning with Generation on slide 16.

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Generation – Market Fundamentals

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New build Cost NPV Operating Margin

Demand growth has been steady, and supply additions have not kept pace:

Power prices have risen, but new build costs have risen faster:

(1) New build Cost based on CEG internal estimates for Gas-Fired CC and Coal. Gas-Fired CT is based on PJM's estimates. Net Revenue for 2007 from PJM's Market Monitoring Report Members Committee, January 24, 2008. Converted into $/KW using 20-yr NPV at 10.0%

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Strong market fundamentals provide a solid foundation for our generation business

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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 face of a tightening supply / demand balance, market prices support new investment in only limited circumstances today.

Given long lead times for 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.


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• Predominantly nuclear and fossil

• Baseload generation contributes 98% of MWhs and 96% of gross margin

• Low CO2 emitting fleet– CEG emissions rate:

0.4 tons/MWh– Industry average is 50% higher

PJM65% MWhs

New York32% MWhs

Renewable Plants

Nuclear PlantsFossil Plants

West3% MWhs

Overview of Generation Fleet

Fleet Facts

MW % of MWhs

Nuclear 3,869 61%

Fossil 4,409 37%

Renewable 450 2%

Our fleet is well-positioned to benefit from the 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 point four tons per megawatt hour. The industry average is fifty percent higher, so we believe that we’re well positioned to respond to and benefit from potential CO2 legislation.

Let me now turn to the earnings outlook for our fleet, starting on slide 18.

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Earnings Outlook

1,7411,3801,4391,093871EBITDA with Hedges(404)(884)(1,116)(1,264)(1,122)Hedge Impact

2,1452,2642,5552,3571,993Unhedged EBITDA(981)(935)(897)(853)(809)O&M

3,1263,1993,4523,2102,802Unhedged GM5150515150Total Output (MM MWhs)

2011E2010E2009E2008E2007($ millions)

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Generation EBITDA, before and after hedge results

Note: Preliminary view of recast historical information

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 gap 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 hedge portfolio should be about zero.


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Hedging and Earnings Variability

Hedge strategy has substantially reduced the fleet’s exposure to changes in energy prices

Impact of Hedging on Generation Earnings Variability

2008E (1) 2009E 2010E

Power (2) + $1 per MWh, fuel unchanged

Fuel + $0.10 per MMBtu, power unchanged

--

Capacity + $10 per MW-day

+$4.1MM +$16.0MM

-- -$0.3MM -$9.4MM

-- +$1.3MM +$14.4MM

(1) Relatively minor residual 2008 position managed within Global Commodities Group portfolio(2) Sensitivities represent energy price changes at the relevant liquid hub only and do not capture the impact of potential changes in

basis from the hub to actual location of each individual power plant

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 the 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 a one dollar per megawatt hour change in power prices would change our generation EBITDA after hedging by 4 million dollars from the forecast shown. A change of 10 cents per MMBtu on our fuel input would change our 2009 EBITDA by less than $1 million, all else held equal.

We have also substantially hedged our capacity position. We’ve 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.


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Operational Performance

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Given that our fleet is largely baseload, the key operational metrics that can cause variability in our results are total energy output and forced outage rate, which affects both energy production and penalties under the PJM capacity program.

Over the last several years, we have accomplished very steady performance relative to both metrics. For perspective, a one percentage point increase in our fossil reliability would increase EBITDA by about $8 million. A one 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…

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Generation Development

Jun-08364Wagner

Reliability Enhancement Projects

Jun-08355Perryman

Apr-10105Nine Mile Point Uprate

Jun-0978Riverside

Dec-0885Alberta Combustion Turbine

Jul-08100Gould Street

TOTAL

TOTAL

Capacity Expansion Projects

719

368

Capacity (MW)

$50MM

$330MM

Total spendIn service date

Weighted average installed cost of capacity expansion projects (~$900/KW) compares very favorably to our estimate of the weighted average replacement cost for similar capacity (~$1,600/KW))

• New gas-fired capacity in Maryland• New nuclear in several locations

Potential Future Development:

In addition to the positive outlook for our existing fleet, the market environment has become conducive to new development under certain circumstances, and we’re pursuing targeted opportunities in three basic 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 MW of operating capacity at an installed cost of about $330 million. At about $900 per KW, this compares quite favorably to our estimate of a weighted average replacement cost for similar greenfield capacity of about $1,600 per KW.

Second, Reliability Enhancement Projects, which are designed to improve our operational reliability 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 MW.

Third, Potential Future Developments, which we are pursuing to create the option 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 billon in capital upgrades to improve environmental performance of 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.


22

22

Agenda

• Generation

• Customer Supply


• Summary

Let me now focus on Customer Supply, starting on Slide 23.

23

23

Customer Supply Overview

Leading power and gas marketer in North America

Wholesale power marketer serving over 16,000 MW of peak load to utilities, co-ops, municipalities, and retail suppliers across North America

Leading retail electricity supplier providing energy products and services to over 15,000 customers and over 75 of the Fortune 100

Natural gas provider serving over 7,500 commercial, industrial, municipal, and local gas distribution and power facilities across North America

2008E Gross MarginRetail Power (42%)

Retail Gas (17%)

Wholesale Power (41%)

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 percent wholesale power, 42 percent retail power, and 17 percent retail natural gas.


24

24

Constellation’s Customer Supply Business

Active in all significant competitive markets

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.


25

25

Strong 2007 Performance

0100200300400500600700800900

2005 2006 2007

$ m

illio

ns

Gross Margin

Customer Supply Group outperformed our expectations in 2007

Our Customer Supply Group turned in a very strong performance in 2007. This result was lead by our retail power group, which increased its gross margin by more than 40%, driven by realizations of 2006 sales originated at attractive unit margins. Likewise our wholesale power group delivered its strongest gross margin year ever. Looking forward, we expect that, due to tightening 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 the 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. Since our retail gas infrastructure had not kept pace with top line growth, we experienced some operational issues in 2007 that hurt results. They have been rectified by integrating retail gas into our overall merchant platform, and we are confident in the outlook for both top line growth and operational performance going forward.


26

26

Customer Supply Volumes

Power

0

50

100

150

200

250

2004 2005 2006 2007 2008E

TWh

Retail Power Wholesale Power

Gas

0

100

200

300

400

500

600

2004 2005 2006 2007 2008E

Bcf

15%11%

Sales volumes have grown at double-digit rates over the last five years

We’ve served retail – we’ve served the 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’ve achieved double digit annual growth rates in both power and natural gas volumes. We continue to see opportunities to grow by acquisitions, organic growth and by penetrating new markets, so we expect this trend to continue.


27

27

Margin Cyclicality

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

2003 2004 2005 2006 2007

Recent Cyclicality of Wholesale Margins

$/M

Wh

Mar

gin

Source: Company analysis of wholesale load auction data

Weather ShocksRecord summer temperatures

and destructive hurricane season led to high prices

Regulatory UncertaintyMarket rules in transition

leading to regulatory uncertainty

• Wholesale margins have cycled between $1.00 to $4.00/MWh• Large C&I retail margins typically exceed wholesale margins $0.50/MWh to

$2.00/MWh

Turning to the margin side, Constellation has been a customer supply leader for nearly a decade. We have 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 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 have 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 averaging $0.50 to $2.00 a MWH higher than wholesale margins. Along with declining margins in 2007, we experienced a bit lower than expected sales volumes as we have 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 15 to 20 cents per MCF and sales volumes were about in line with expectations.


28

28

Customer Supply Backlog

0

100

200

300

400

500

600

2008E 2009E 2010E

Wholesale power Retail power (1) Retail gas (2)

Gro

ss M

argi

n$

mill

ions

(1) Retail Power backlog includes renewals (68% renewal rate) (2) Retail Gas backlog includes renewals (94% renewal rate)

Given our basic model of selling energy products to customers over terms typically ranging from six months to two years, our Customer Supply business is supported by a backlog of gross margin sold in prior periods and expected to be realized in future periods.

Note that our 2008 total backlog of $535 million represents about 73 percent of our expected 2008 gross margin, slightly better than the backlog of 71% of gross margin in last year’s plan at this time.


29

29

Customer Supply Growth Initiatives

• We expect the demand response market to grow to over 20,000 MW by 2010

• CSG retail power peak load of 16,000 MW converts to roughly 2,000 MW of demand response potential

Small and Medium Businesses (“SMB”)

Indirect Channel (Brokers & Aggregators) Demand Response

Rationale

Approach• Leverage market-leading retail

sales force to drive growth in demand response through existing customers and prospects

• Currently underserved by CSG relative to Large C&I market

• CSG share: 9% of SMB switched market vs. 24% of Large C&I

• 60% larger total market than Large C&I

Rationale

Approach• Expand on successful Texas

model, hiring and training direct sales force in attractive markets such as IL, NY, New England

• Augment direct sales team with direct marketing, internet & third party sales channels to find the most effective, low-cost acquisition/retention model

• Represents 50% of industry average retail volumes but only 30-40% of CSG volumes

Rationale

Approach• Build a national sales and

marketing platform focused on serving the needs of electricity brokers and consultants

• Provide indirect customers the market intelligence, execution capabilities and products to grow and manage their businesses

CSG growth initiatives expected to add $125 million to backlog in 2008, resulting in 77% year-over-year growth

Turning briefly to growth opportunities, in 2008, we’ll be targeting growth in three key areas of our retail power business: sales through brokers and aggregators, sales to smaller commercial and industrial 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 in 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 3,000 MW 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 volumes by about a third.


30

30

Customer Supply Earnings

(295)(305)(223)(171)Operating expenses

304 380 319 231 Wholesale

EBIT

Gross Margin

Retail

$ millions

436

659

340

2006

276

447

216

2005

442495

737 800

433 420

2008E2007

Note: Results shown here do not include historical gross margin impact of managing certain wholesale load-related risks, primarily weather and customer behavior. Historically these impacts have been included in the Commodities Group’s Portfolio Management & Trading results (loss of $121MM in 2005, gain of $160MM in 2006, and loss of $1 MM in 2007). Because these risks are intrinsic to our Customer Supply activities, we will reflect their impact in our Customer Supply results prospectively.


0

100

200

300

400

500

600

2005 2006 2007 2008E0%

10%

20%

30%

40%

50%

60%

EBIT OpEx % of Gross Margin

EBIT

($ m

illio

ns)

OpE

x%

of G

ross

Mar

gin

Looking at our Customer Supply earnings picture, you can see theimpact 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 percent 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 we ascribe to lower volatility and the absence of price shock events.

The operating expense line shown here includes an allocation from Global Commodities to Customer 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 investment 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 results, but we do expect a strong year. We expect EBIT to grow annually at 17 percent from 2005 to 2008.


31

31

Agenda

• Generation

• Customer Supply


• Summary

Let me now focus on our Global Commodities Group starting on slide 32.

32

32

Global Commodities Overview

Direct investment in energy assets that are strategically connected to our core businesses. Primarily gas production assets and dry-bulk cargo ships

Customized risk management products for customers in the power, gas, coal, and freight markets (e.g., generation tolls, gas transport and storage, and global coal logistics)

2008E Gross Margin

Structured Products (28%)Energy Investments (25%)

Centralized risk management services for entire merchant combined with Trading arm

Portfolio Management & Trading (47%)

Our Global Commodities Group handles all of Constellation’s risk management and oversees Merchant risk taking activities in energy markets. Our 2008 planned gross margin of $828 MM will fall into three categories:

• Portfolio Management & Trading, comprising 47 percent

• Structured Products, comprising 28 percent, and

• Energy Investments, 25 percent.

Let me touch briefly on each area, starting on slide 33.

33

33

Portfolio Management & Trading

Gross Margin

• Total Portfolio Value-at-Risk(1) of $17 million (includes both mark to market and accrual portfolios)• Mark to Market Value-at-Risk(1) of $13MM

Power Marketing and Trading

# 1 power marketer and trader for last four years Becoming one of the largest natural gas players

($100)($50)

$0$50

$100$150$200

Q1'03

Q2'03

Q3'03

Q4'03

Q1'04

Q2'04

Q3'04

Q4'04

Q1'05

Q2'05

Q3'05

Q4'05

Q1'06

Q2'06

Q3'06

Q4'06

Q1'07

Q2'07

Q3'07

Q4'07

$MM

% of FERC

reported volumes

5.9

8.1

10.0

2.2

0

2

4

6

8

10

12

2004 2005 2006 2007

Bcf/day

Rank: #17 #6 #5 #3

2.6%

4.7%5.9%

7.5%8.2%

7.6% 7.6%

0%

2%

4%

6%

8%

10%

2001 2002 2003 2004 2005 2006 2007Rank: #13 #5 #3 #1 #1 #1#1

(1) One day, 95% Value-at-riskSource: Platts, Company

Gas Marketing and Trading

Our Portfolio Management & Trading group manages all the price risk associated with Constellation’s generation fleet, our customer supply business, both wholesale and retail, and our structured productsportfolios. It also deploys risk capital in traded energy markets.

Our Portfolio Management & Trading activities are supported by avery strong market position. We’ve been the number one player in U.S. power markets for the last five years. We’ve 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 the strong and steady results that you see shown 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.


34

34

Structured Products

Natural Gas Transportation & Storage

• Contractually control 15 Bcf of storage and 1.2 Bcf/day of transportation

Contractually Controlled Power Generation

• 4,500 MW portfolio, generated from multiple fuel types and geographic areas

• Average contract term remaining 6 years

International Coal Sales

• Delivered 22 million short tons to US and international customers in 2007

Structured Products is a steady earnings producer, leveraging broad customer relationships and risk management capability

0

20

40

60

80

100

120

140

160

180

2008E 2009E 2010E 2011E 2012E

Portfolio value to be realized ($MM)

Structured Products Backlog

In Structured Products, we originate longer term customer risk management transactions in three key areas:

• Contractually Controlled Power Generation includes the margin from long term contracts we’ve entered into to purchase power from generators in support of our Customer Supply activities.

• US and 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 backstops supply to our customer business.

The earnings from these activities are generally recognized as the physical commodities are delivered. As you see, our total Structured Products backlog amounts to $612 million to be realized over the next five years.


35

35

Energy Investments

• Own nine producing properties• Acquired largely in 2006 and 2007• Portfolio includes ownership interest in

Constellation Energy Partners (1)

• 355 Bcfe proved reserves (including interest in CEP)

Natural Gas Production Coal and Freight

• Jointly own six dry-bulk shipping vessels

• Employed as part of international coal supply business

• Purchased during 2007

Natural Gas Production Investment Summary Freight Asset Investment Summary($ millions)($ millions)

(1) Constellation Energy Partners (NYSE Arca: CEP) is an oil and gas MLP in which CEG holds a stake(2) Internal estimates based on market comparables

307Implied net gain

1,000Current market value (2)

693Net Basis

(230)Realized to date

923Invested capital

75Implied net gain

125Current market value (2)

50Net Basis

-Realized to date

50Invested capital

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 relied upon our core skills in valuation and risk management. They’ve been in two key areas – natural gas production and dry bulk freight.

In total we’ve invested just under $1 billion, mostly in the last two years, and generated a gain, both realized and unrealized, of about 40 percent.

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.


36

36

Global Commodities Earnings

391435437Portfolio Management & Trading (2)

441241302EBIT(387)(400)(312)Operating Expenses

23197132Structured Products

Gross Margin

Energy Investments (1)

$ millions

614

45

2006

828641

206109

2008E2007

0

100

200

300

400

500

2006 2007 2008E0%

10%

20%

30%

40%

50%

60%

70%

EBIT OpEx % of Gross Margin

EBIT

($ m

illio

ns)

(1) Upstream Gas Reported as Contribution Margin(2) Included in historical Portfolio Management & Trading result is the gross margin impact of managing certain risks that are intrinsic to the

Customer Supply business, primarily weather and customer behavior (a gain of $160MM in 2006 and a loss of $1MM in 2007). Because these risks are intrinsic to our Customer Supply activities, we will reflect their impact in Customer Supply results prospectively.


OpE

x%

of

Gro

ss M

argi

n

Looking at the total Global Commodities Group earnings picture, three things are worth noting:

First, we are experiencing meaningful growth from Structured Products and Energy Investments areas, where we have 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 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 investment.

In total we expect EBIT to grow at an annual rate of 21 percent over the 2006 to 2008 period.


37

37

Agenda

• Generation

• Customer Supply


• Summary

Let me quickly summarize, starting on slide 38.

38

38

Integration Update

NEW ENERGY

SALES

CUSTOMER CARE

MID & BACK OFFICE

LEGAL & REGULATORY

SUPPLY & RISK MANANGEMENT

NEW ENERGY GAS

SALES

CUSTOMER CARE

MID & BACK OFFICE

LEGAL & REGULATORY


COMMODITIES GROUP

SALES

CUSTOMER CARE

MID & BACK OFFICE

LEGAL & REGULATORY


CUSTOMER SUPPLY GLOBAL COMMODITIES GROUPWholesale Load Business

INTEGRATION PHASE I

• First phase of integration has focused on portfolio management and back office activities• Later phases will focus on integrating sales (cross sell) and customer care activities

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 Group will now handle all of the supply and risk management functions for our Customer Supply Group and generation fleet. We also combined mid and back office functions to leverage scale and improve efficiency.

This has led to some cost leverage. We expect Phase 1 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.


39

39

Summary – Priorities for 2008• Generation

– Execution of capital projects– Continued improvements in operational reliability

• Customer Supply– Continue driving sales volumes– Increase focus on growth segments

• Global Commodities– Continue to execute on return-oriented risk management

and trading approach– Leverage customer franchise through Structured Products

and Energy Investments activities

To close, our key priorities for 2008 are simple:

In Generation, we’ll be focused on operating efficiently and executing on capital projects to expand our capacity and improve our environmental performance. We’ll 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 investment, trading and risk management approach.

Now I’d like to turn things over to Mike Wallace to discuss our new nuclear initiative.

40

New Nuclear

Michael J. WallacePresident and CEO Constellation Energy Nuclear Group

Constellation Energy

Thanks, Tom, and good morning everyone.

In my presentation I’m 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.


41

41

Driving Forces for New Nuclear

New Nuclear Plants

Energy

Security

Climate Change

(CO2)

Congressional

Support

Falling Reserve

MarginsRising Gas

Prices

Public

Support

A number of driving forces are coming together that are particularly supportive of new nuclear plants being built in the 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 rising 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 percent of public opinion now in favor of new nuclear. Additionally, and very importantly, we have congressional support, from both the Senate and 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 in to the energy mix. Today momentum continues and we are working to make new nuclear a reality.


42

42

UniStar

Flamanville 3EPR

Nine Mile 3USEPR

Calvert Cliffs 3USEPR

Berwick 1USEPR

Callaway 2USEPR

Constellation Energy took its first step in 2005 when we formed UniStar to pursue new nuclear development activities by jointly marketing the U.S. EPR technology with Areva. Since then, we have been working to position Constellation and Unistar as the U.S. 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 online 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 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 U.S. EPR. Most recently, in November we added Alstom to the team as the supplier of the 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 U.S. EPR.

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.


43

43

Calvert Cliffs Unit-3 Potential Timeline

Break GroundCommercial Operation

License Issued

First Concrete

EARLY SITE WORK

COMBINED LICENSE

CONSTRUCTION

DATA COLLECTION

STATE PERMIT

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

NRC REVIEW

DESIGN CERTIFICATION

NRC REVIEW

STATE REVIEW

Licensing

Construction

• Calvert Cliffs is used here as a reference plant

• Accelerating activities at Nine Mile Point

So let’s look specifically at the time line for building the first U.S.EPR. 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 time line since we have not yet made the final decision to construct a new nuclear plant. Nevertheless, all of the front-end activities shown on this chart in 2006 and 2007 has been accomplished. The design certification has been filed with the Nuclear Regulatory Commission, part of our combined operating license application has been filed and 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 those applications, and they are now under review.


44

44

Driving Down the Level of Uncertainty

Current Risk Assessment

Risk environment being managed Driving down the level of uncertainty

As we have progressed over the last three years, we have taken a risk-managed approach to pursuing 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 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 red. 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 of 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 risk, 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 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 a commercial operation date of 2015. Overall, we have been managing the risk environment, and as a result, the overall risk profile is greatly improved and supports the continued expansion of nuclear development activities.


45

45

Summary• Leadership in new nuclear

• Disciplined, risk-managed approach

• Right Team - UniStar Nuclear brings together nuclear industry leaders with complementary skills

• Right Technology – U.S. EPR utilizes existing technologies to minimize first-of-a-kind risk

• Right Time – Market factors, environmental benefits and the passage of the EPAct of 2005 are coming together in support of new nuclear

In summary, we have been exercising leadership in the nuclear industry since 2005 as we pulled 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 obviates 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 U.S. EPRs. 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 U.S. EPR 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 ensure that the DOE had the authority to move forward with the 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'll turn it over to John for the financial review.

46

Financial Overview

John R. CollinsExecutive Vice President and Chief Financial Officer

Constellation Energy

Thank you, Mike. Good morning everyone. Welcome to New York Glad to see you today.


47

47

Agenda - Financial Overview

• 2007 Results Discussion

• 2008 Forecasted Results Discussion

• Beyond 2008

I’ll start this morning by highlighting a few of our financial successes during 2007, then review our 2007 results, before turning to a review of our 2008 forecasted results. I will wrap up by reviewing our financial outlook beyond 2008.

Moving to slide 48…

48

48

Financial Success in 2007• Drove substantial earnings growth of 27% over strong 2006

performance – Toward the top of our upwardly revised 2007 guidance range

• Delivered total shareholder return of 52%

• Completed $623 million BGE securitization to finance rate deferrals

• Refinanced $3.85 billion 5-year revolving credit facility to replace existing bank facilities

• Created UniStar Nuclear Energy joint venture with EDF

• Completed $250 million of $1 billion share repurchase program

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 percent over 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 percent in 2007, well above both the S&P Utility and the 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 was one of the fastest executions of a utility securitization. As of January 1 of this year, all of BGE’s customers have completed the transition to full market rates.

• In July, we refinanced our existing liquidity facilities into a $3.85 billion, 5-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 initiative. As part of this agreement, EDF is permitted to purchase up to 10 percent of Constellation stock in the open market with a 5 percent limit in the first 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.

49

49

Adjusted Earnings Per Share

0.050.05Merchant

(0.07) -Wind Farm Asset Impairment

Maryland Corporate Tax Rate

0.020.11Add: Synfuel Loss

(0.05) (0.05)BGE

$4.30 - $4.65Early 2007 Guidance

(0.01)-Workforce reduction costs

($0.09)$0.00Total Special Items

2007Q4 2007Special Items($0.01)-Discontinued Operations – High Desert/Puna (tax)

$4.45 - $4.65$1.35 - $1.55October 2007 Guidance

$4.60$1.48Adjusted Earnings Per Share (1)

(0.01)(0.05)Less: Gain on Economic Non-Qualifying Hedges

0.090.00Add: Special Items

$4.50$1.42GAAP Earnings Per Share

2007Q4 2007($ per share)

(1) Excludes special items, certain economic, non-qualifying hedges, and synfuel earningsSee Appendix

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 $4.50 per share. Let me walk you through the adjustments to GAAP for the full year 2007.

• We had a 9-cent loss related to special items driven primarily by a 7-cent charge recorded 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 2-cent loss for the year driven by an increase in tax credit phase-out due to higher oil prices.

• We had a 1-cent gain on economic, non-qualifying hedges associated with gas storage, which we adjust out of GAAP earnings.

• Lastly, we had offsetting 5-cent 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 our guidance range of $4.45 to $4.65 per share, which we revised upward at the end of the third quarter.


50

50

4th Quarter 2007 Adjusted EPS Summary

37%$0.40$1.08$1.48Adjusted Earnings Per Share

$1.35 - $1.55Q4 2007 Earnings Guidance

N.M.0.020.020.04Other Non-regulated

(6%)($0.01)0.180.17BGE

44%$0.39$0.88$1.27Merchant

%EPSQ4 2006Q4 2007($ per share)

ChangeAdjusted Earnings Per Share (1)


+6¢ Interest & Share Accretion

+7¢ Generation

+10¢ Retail Competitive Supply

-2¢ Other+18¢ Wholesale Competitive Supply

Merchant Variance (Q4 2007 vs. Q4 2006)

Now let’s look at operating results by segment compared to the fourth quarter of 2006. The Merchant segment was up 39 cents per share, driven by several factors:

• Wholesale Competitive Supply was up 18 cents per share due to higher backlog and new business realization.

• Our Competitive Supply businesses, NewEnergy Electric and NewEnergy Gas, were up 10 cents per share. NewEnergy Electric’s performance was up 4 cents per share, continuing the recent trend of strong realized margins. NewEnergy Gas was up 6 cents per share as we saw the reversal of mark-to-market losses recorded in prior periods.

• Generation was up 7 cents per share driven primarily by the absence of the Ginna refueling outage in the fourth quarter of 2006.

• We had lower interest expenses due to a larger cash balance and higher short-term interests rates, combined with share accretion, which increased earnings by 6 cents per share.

• There were a number of smaller items that net to negative 2 cents per share.

BGE’s results were down 1 cent per share versus last year, driven by credits 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 2 cents per share.

Overall, adjusted earnings were up 40 cents to $1.48 per share on a quarterly basis in line with our expectations.

Turning to slide 51...

51

51

Full Year 2007 Adjusted EPS Summary

$4.30 - $4.65Early 2007 Guidance

27%$0.99$3.61$4.60Adjusted Earnings Per Share

$4.45 - $4.65October 2007 Guidance

N.M.0.030.060.09Other Non-regulated

(15%)(0.13)0.870.74Utility

41%$1.09$2.68$3.77Merchant

%EPS20062007($ per share)

ChangeAdjusted Earnings Per Share (1)


+2¢ Retail Competitive Supply

+1¢ Wholesale Competitive Supply

-5¢ Other+34¢ Interest Expense & Dilution

-13¢ Sale of Gas Plants+90¢ Generation

Merchant Variance from 2006

For the full year 2007, adjusted earnings were $4.60 per share, up 99 cents or 27 percent 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 90 cents per share primarily driven by the roll-off of below market hedges, the impact of the Ginna Uprate, which was completed in the fourth quarter of 2006, and fewer planned outage days. These were partially offset by the end of competitive transition charge collections, inflation and higher operating costs.

• Net interest expense was 36 cents per share favorable due to higher average cash balances combined with higher short-term interest rates, partially offset by 2 cents of dilution for the full year.

• Our Retail Competitive Supply businesses, NewEnergy Electric and NewEnergy Gas, were up 2 cents per share. NewEnergy Electric’s performance was up 27 cents per share primarily due to higher realized rates. NewEnergy Gas was down 25 cents 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 1 cent 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 13-cent per share variance.

• There were a number of other small items that net to negative 5 cents per share.

BGE’s earnings were down 13 cents per share compared to 2006 primarily driven by the credits to residential customers required by Maryland’s 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.


52

52




• Beyond 2008 Expectations

We will now discuss Constellation’s 2008 forecasted results, starting on slide 53.

53

53

Financial Themes for 2008

• New Integrated Merchant reporting framework for 2008

• Continued strong adjusted earnings growth of 14% to 25%

• Additional growth in capital investment– Environmental controls– Increase in generation capacity and reliability– Investment in growth initiatives

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 percent 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…

54

54

Integrated Merchant Reporting Framework for 2008

New 2008 Merchant Reporting FrameworkPrior Merchant Reporting Framework

QFs / Other

Mid-Atlantic Fleet

Plants with PPAs

New Energy

Wholesale Competitive Supply

Generation

Customer Supply

Global CommoditiesPower Load Serving

As Mayo and Tom discussed, we are realigning the Merchant activities to capture operating synergies and drive long-term sales growth. As part of this process, we are revising 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 plants in one bucket. Customer Supply comprises NewEnergy, which serves retail gas and electriccustomers, and the power load serving portion of Wholesale Competitive Supply. The 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...

55

55

Merchant Modeling Information

Merchant

Generation Customer Supply

GlobalCommodities

• Unhedged EBITDA

• Value of Hedges

• Impact of Hedging on EBIT

• Backlog

• Annual Gross Margin Targets

• Annual EBIT Forecast

• New Business Margins

• Annual Gross Margin targets

• MTM and Total portfolio VaR

• Structured Products Backlog

• Annual EPS guidance

50%

25%

25%

Generation Customer Supply Global Commodities

2008E Merchant EBIT

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 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 baseloadprofile 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, an annual EBIT forecast, and new business margins.

Finally, we share 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 structured products within Global Commodities.

We believe the combination of the additional information we have provided related to the various business activities within our Integrated Merchant segment, and these specific metrics will help you to better model and value the Merchant segment.


56

56

Substantial Earnings Growth in 2008

Change vs. Mid-point

$0.90

(0.06)

(0.04)

$1.03

$

2008 Earnings Outlook

$4.60

0.09

0.74

$3.77

2007 (1)

20%

(5%)

N.M.0.02 – 0.04 Other Non-regulated

$5.25 - $5.75Adjusted Earnings Per Share

0.65 – 0.75Utility

$4.55 – $5.05Merchant 27%

%2008E(1)($ per share)

See Appendix

(1) Excludes special items, certain economic, non-qualifying hedges, and synfuel earnings

For 2008, we are reiterating our guidance range of $5.25 to $5.75 per share, which represents 14 to 25 percent 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 percent and BGE to earn between 65 and 75 cents per share, down 5 percent from 2007.

Turning to slide 57, we’ll discuss the specific earnings drivers…

57

57

2007 to 2008 Earnings Walk – Summary

• Earnings Drivers:– Generation – continued roll-off of lower priced hedges– Global Commodities – higher backlog, partly offset by lower new business in 2008 following a strong 2007– Customer Supply – lower wholesale power backlog and lower retail electric margins, partially offset by

higher earnings in retail gas(1) Excludes special items, certain economic, non-qualifying hedges, and synfuel earningsNote: Analysis assumes 2008 mid point of EPS guidance rangeSee Appendix

($ p

er s

hare

) (1)

2007 2008

Generation

Inflation

GlobalCommodities

BGEOther Merchant Other

Non-Regulated

Interest Expense

and Share Accretion

Customer Supply

$ 5 .2 5 - $ 5 .7 5

$ 4 .6 0

(0 .0 6 )(0 .02 )

(0 .0 5 )

(0 .11 )

(0 .18 )

(0 .0 8 )

0 .73

0 .6 7

$ 4 .2 5

$ 4 .5 0

$ 4 .7 5

$ 5 .0 0

$ 5 .2 5

$ 5 .5 0

$ 5 .7 5

$ 6 .0 0

Overall, we expect our Integrated Merchant segment to be up 98 cents 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 73 cents 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 67 cents 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 18 cents 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 in 2008. We experienced retail power margins in 2007 of $5.39 per MWh and we are projecting margins of $3.80 per MWh 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 13 cents per share and include higher interest, taxes, and other costs, partially offset by share accretion following the November 2007 share buyback.

We expect BGE’s earnings to be down 2 cents, primarily due to higher operating costs and higher interest expense, partially offset by higher revenue due to customer growth and higher Transmission 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 per customer arising from our energy conservation programs for residential and small commercial customers. Lastly, while we expect 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 & Services, as well as the absence of tax credits in 2007.

Now, turning to slide 58…

58

58

Capital Spending

648185Other Non-regulated / Corporate

(168)(742)251Change

1,6621,7061,916Prior Plan

562493402Utility Total

$ 1,204$ 1,874$ 1,178 Merchant Total

$ 1,830$ 2,448$ 1,665Total Capital Expenditures

2009E2008E2007($ in millions)

• Key drivers of 2008E increase in capital expenditures:– Ramp up in spending for environmental controls; shift of costs from 2007 to 2008– Generation capacity additions and reliability improvements– Increased BGE infrastructure requirements and conservation initiatives

See Additional Modeling page 87

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 shareholder return in other ways, such as the share repurchase program.

Let’s turn to slide 59 for a detailed view of Merchant spending.

59

59

Capital Spending - Merchant

148

9341,6711,030Merchant Capital Expenditures (excluding Nuclear Fuel)270203Nuclear Fuel

$ 335$ 548$ 157Major Environmental

- Baltimore CT Reliability Improvement

- Nine Mile Point Extended Power Up rate (EPU)

- Other Merchant

- Existing Upstream Gas (E&P) Projects

186354175Existing Growth

- Generation (Excluding Major Environmental)

251

1,429

$ 1,178

359

339

2007

$ 1,204$ 1,874Total Merchant Capital Expenditures

(52)(641)Change

1,1521,233Prior Plan

-385Opportunistic Growth

413385Maintenance Capital Spending

2009E2008E($ in millions)

Note: Numbers may not add due to rounding

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. Relative to the 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 Scrubber projects. While the timing of the capital spending has changed, overall the projects remain on schedule, with total project spend consistent with the previous plan.

Our planned maintenance capital spend of $385 million for Generation and other Merchant projects primarily includes 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 generation capacity.

We have also included $385 million in our capital budget to invest in new growth 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…

60

60

Capital Spending - BGE

557662Electric Transmission

$ 428$ 366$ 339Electric / Gas Distribution

79511Demand Response & Conservation / Other

(109)(78)20Change

453415422Prior Plan

$ 562$ 493$ 402Utility Total

Baltimore Gas & Electric

2009E2008E2007($ in millions)

• Key drivers of capital expenditures:– Demand response and conservation initiatives– BGE infrastructure requirements– Advanced Metering Initiative is not included in current capital plan; deployment could increase

capital plan by $80 to $100 million in 2009

In 2007, the utility 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 accommodate 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 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 reliability will necessitate BGE filing a rate case in 2008, and subsequent rate cases thereafter to support the higher levels of capital. The 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…

61

61

2008E Consolidated Cash Flow

See Appendix

206--206Asset Disposition & Contract Restructuring

(6)---Pension Adjustment (pre-tax)

759(117)183Working Capital & Other

(419)14(147)(280)“Operating” Cash Flow

($529)(337)(34)

(158)55

(1,497)(2,296)

799

$1,009

2008E Total

-55-SB1 Rate Deferral

Equity – Benefits Plans

10272517Depreciation & Amortization

$ 6$ 130$ 873Net Income

Net Cash Flow before Debt Issuances/(Payments)Dividends

14(92)(74)Free Cash Flow

(1)(160)(1,336)Net CapEx(11)(432)(1,853)Capital Expenditures / Investments

Other Non-RegUtilityMerchant($ in millions)

• Operating Cash Flow will be a use of $419 million in 2008 primarily driven by increased capital expenditures

Bringing the capital and earnings picture together, in 2008, we expect operating cash flow to be a use of approximately $400 million. As you can readily see from the chart and heard in our prior discussion on capital spending, the $2.3 billion of capital spending 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 percent increase in the dividend from $1.74 per share to $1.91 per share. This represents the 5th year in a row that we have increased the dividend by at least 10 percent. Similar to the past two years, we did not grow the dividend in line with earnings growth, which would have been a 27 percent increase from 2006 to 2007. The 10 percent growth rate is very robust for a company with our growth prospects, and the resulting payout ratio of 34 percent is appropriate for 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.


62

62

2008E Balance Sheet / Credit Metrics

0.40.40.30.3-3rd Party Cash Collateral

0.90.90.91.4-AOCI Balance

34% - 38%35% - 39%36%35%55%Net Debt to Total Capital(2)

41% - 45%

34% - 38%

$10.7

6.2

$0.1

$4.4

(0.6)

$5.0

YE 2008E

33% - 37%35%32%55%Adjusted Net Debt to Adjusted Total Capital(3)

$0.1$0.1$0.1$0.150% Trust Preferred

Capital

$4.6$3.8$2.7$5.1Net Debt

7.25.64.94.1Equity (1)

(0.5)(1.1)(2.3)(0.1)Less: Cash

$11.9$9.5$7.7$9.4Total Capital

$5.1$4.9$5.0$5.2 Total Debt

47% - 51%28%16%19%FFO / Debt(2)

Debt

YE 2009EYE 2007YE 2006YE 2001($ in billions)

(1) Includes preferred stock and minority interest(2) Excludes BGE Rate Stabilization Securitization debt(3) Excludes BGE Rate Stabilization Securitization debt, AOCI balance related to cash flow hedges of commodity transactions and 3rd

party cash collateralNote: Numbers may not add due to roundingSee Appendix

The balance sheet and resulting credit metrics continue to be strong.

Net debt-to-capital at the end of 2007 was 36 percent. This is slightly higher than the 35 percent at year-end 2006 which was bolstered by the large cash balance due to the proceeds from the 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 of 2007; however, since we include the BGE rate deferral securitization in the reported total debt balance, you don’t see the pay down of the $600 million.

Net debt to 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/Debt ratio which is the most important ratio for the rating agencies. In 2006 and for part of 2007, the BGE deferrals were a drag on FFO. With the deferrals over, we see a significant increase – at least 10 percentage points – in the FFO/Debt metric.

When the rating agencies look at this metric, they increase the amount of debt by imputing debt from power purchase agreements, pension obligations, trading 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 percent range versus our forecast of 41 to 45 percent.

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.


63

63

Quarterly Earnings

• Important for investors to focus on full-year projections and long-term earnings prospects

64% 64% 65%76%

84%

36% 36% 35%24%

16%

0%

20%

40%

60%

80%

100%

2003 2004 2005 2006 2007

Non-Reg Utility

Non-Regulated vs. Utility Percentage Contribution to Annual EPS

13%20% 19% 17% 22%

21%17% 17%

13%14%

42% 38% 34% 40% 32%

24% 25% 30% 30% 32%

0%

20%

40%

60%

80%

100%

2003 2004 2005 2006 2007

Q1 Q2 Q3 Q4

Quarterly Earnings as a Percentage of Annual Earnings

Before I move onto the outlook beyond 2008, I want to discuss quarterly guidance and roll out 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 tool in gauging the performance of the business.

The 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 variability 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 on our quarterly results.


64

64

Modification of Quarterly Guidance• Modifying quarterly guidance approach

– Replace quarterly total company EPS guidance with other operating and financial metrics

– Annual EPS guidance will continue for the prompt year, with growth percentage guidance for the subsequent year

$247$218Generation Hedged EBITDA (1) ($ in millions)

$0.33 – $0.38$0.36BGE Earnings Per Share

$57$56Customer Supply Backlog ($ in millions)

Guidance1Q08E

Actual1Q07

See Appendix(1) Excludes allocation of Corporate Costs

As a result, consistent with almost all other integrated energy companies, we have chosen to eliminate specific 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 businesses.

So let me walk you through our approach. We are providing a BGEearnings per share range, which we expect to be 33 to 38 cents in the first quarter of 2008.

For Generation, we are providing a hedged EBITDA forecast for the prompt quarter. For the quarter, we expect to realize hedged EBITDA of $247 million, which is $29 million higher than in 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 that should help you model the company.


65

65




• Beyond 2008 Expectations

Now let’s take a look at the longer term outlook starting on slide 66.

66

66

2009 & Beyond Forecast

• Anticipating continued strong growth beyond 2008– Forecasting 2009 EPS growth of 15% to 20% over 2008– Expect compound annual growth rate of greater than 10% over the next 5

years

$2.89

$3.61

15% - 20 %

$5.25 - $5.75

$4.60

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

2005 2006 2007 2008E 2009E

Compound Annual Earnings Growth of 20% - 24%

Adj

uste

d EP

S (1

)

($ per share)

(1) Adjusted for the effect of special items, certain economic, non-qualifying hedges, and synfuel earningsSee Appendix

Looking beyond 2008, we are forecasting continued strong growth.In August, we told you that we were expecting growth in 2009 of greater than 10 percent. We are now confident that in 2009 we can achieve 15 to 20 percent 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 percent, which may not be linear.

Let’s turn to slide 67 to wrap up the financial section.

67

67

Return on Invested Capital

CEG +145%

S&P Elec +68%

S&P 500 +16%

Strong, disciplined approach to capital investment drives performance and total shareholder return

7.0%

7.5%

8.0%

8.5%

9.0%

9.5%

10.0%

10.5%

2003 2004 2005 2006 2007

Total Company ROIC Total Shareholder Return

(-20%)

0%

20%

40%

60%

80%

100%

120%

140%

160%

12/31/04

2/28/ 05

4/30/ 05

6/30/ 05

8/31/05

10/31/05

12/31/05

2/28/ 06

4/30/ 06

6/30/ 06

8/31/06

10/31/06

12/31/06

2/28/ 07

4/30/ 07

6/30/ 07

8/31/07

10/31/07

12/31/07

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 rigorous analysis to ensure we continue to be good stewards of your capital by investing in opportunities that exceed their appropriate risk-adjusted cost of 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’ll turn the podium back over to Mayo for concluding remarks.

68

Constellation EnergyAnalyst Day Presentation

Mayo A. ShattuckChairman, President and Chief Executive Officer

Thanks, John.

69

69

Investment Thesis• Projecting 15% to 22% compound annual earnings growth from 2007 to

2009– Highly hedged generation fleet provides clear and substantial earnings growth

• Supported by high-quality assets in high-value markets– Low-cost baseload nuclear and coal generation capacity

– Low-emitting plants well-positioned to benefit from future greenhouse gas regulation

• Established significant growth platforms to meet customer needs

• Capital investment opportunities create potential for future earnings growth and shareholder return

• Management team has delivered superior earnings growth and totalshareholder return

So, throughout this presentation, you’ve heard me, Tom, 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 thesis 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 percent following on 2006’s increase of 27 percent.

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 constrained carbon environment.

Third, we see opportunities to deploy capital that will create 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 other 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 this presentation, we’re poised to continue this in the future.

So this concludes our prepared remarks. We would now like to open it up to questions.

70

Additional Modeling

71

71

Additional Modeling• CEG Financial Results

– Reconciliation from GAAP to Adjusted EPS p. 72

– Earning Variance Analysis p. 74

– Wholesale Competitive Supply p. 75

– Merchant Income Statement p. 76

– Segment Cash Flow p. 78

– Excess Liquidity p. 79

– Synfuel Update p. 80

• CEG Financial Outlook

• Customer Supply


• Generation

• BGE

72

72

Full Year Reconciliation from GAAP to Adjusted EPS

2007

$4.60

0.02

(0.01)

0.01

0.08

$4.50

$3.61

(0.16)

(0.21)

(1.04)

(0.14)

$5.16

20062005($ per share)

0.14Non-Qualifying Hedges

(0.33)Synfuel Earnings

$2.89Adjusted EPS

(0.53)Discontinued Operations

0.14Special Items

$3.47GAAP EPS

This chart details the reconciliation of GAAP earnings to adjusted earnings per share for the last three years. In addition to GAAP EPS, we present adjusted EPS because we believe it is appropriate for investors to consider results excluding special items, discontinued operations, impact of non-qualifying hedges and synfuel earnings. We believe this provides a picture of our results that is more comparable among periods since it excludes the impact of items such as workforce reduction costs or gains or losses on the sale of assets, which may recur occasionally, but tend to be irregular as to timing, thereby distorting comparisons between periods.

For the full year 2007, GAAP earnings were $4.50 per share. To arrive at adjusted EPS, we first adjust for 8 cents per share of special items, which include a windfarm asset impairment of 7 cents and 1 cent of workforce reduction costs. We then adjust for the tax impact of 1 cent per share related to the sale of High Desert/Puna, which was required to be reclassified to discontinued operations under FAS144, and subtract from GAAP EPS a gain of 1 cent on non-qualifying hedges. The final adjustment is to add a 2 cent loss from synfuel operations to arrive at adjusted EPS of $4.60 per share.

73

73

Quarterly Reconciliation from GAAP to Adjusted EPS

$1.08$1.46$0.45$0.61Adjusted EPS

(0.04)(0.11)0.01(0.02)Synfuel Earnings

(0.07)(0.20)-0.06Non-Qualifying Hedges

(0.76)(0.10)(0.11)(0.07)Discontinued Operations

(0.27)0.080.030.01Special Items

$2.22$1.79$0.52$0.63GAAP EPS

Q4Q3Q2Q1

2006

2007

$1.48

0.11

(0.05)

-

-

$1.42

Q4Q3Q2Q1($ per share)

(0.01)(0.01)0.05Non-Qualifying Hedges

0.09(0.07)(0.10)Synfuel Earnings

$1.45$0.64$1.03Adjusted EPS

(0.01)-0.01Discontinued Operations

-0.08-Special Items

$1.38$0.64$1.07GAAP EPS

Note: The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

This chart details the quarterly reconciliation of GAAP EPS to adjusted EPS for 2006 and 2007.

Fourth quarter 2007 GAAP earnings were $1.42 per share. To get to adjusted EPS, we recognized a gain of 5 cents per share on non-qualifying hedges and a loss of 11 cents per share on our synfuel facilities. This results in a fourth quarter adjusted EPS of $1.48 per share, which was well within our guidance range of $1.35 to $1.55 per share.

74

74

2007 Earnings Variance Analysis

-(0.13)(0.13)Gas Plant EBIT Ex: High Desert

0.070.270.34Interest and Dilution

(0.01)(0.08)(0.09)Inflation

(0.02)0.030.01Other

$0.12$4.30 - $4.65$4.602007

(0.13)

0.13

0.00

0.17

(0.08)

(0.14)

0.88

0.03

$3.61

Actual

(0.17)

0.22

(0.02)

0.20

(0.04)

(0.14)

0.92

(0.19)

$3.61

Forecast

-CTC

(0.04)Mid-Atlantic Fleet

(0.03)Planned Outages

(0.04)PPA’s

(0.09)Productivity

0.02Other Generation

0.04BGE

0.22Competitive Supply

$-2006 Adjusted EPS

Variance

See Appendix

2007 Forecast Earnings Walk (January 2007)($ per share)

$ 3.6 1

2 0 07$4 .30 - $4 .65

( 0 .19 )

BGE(0 .1 7)

Other

(0.02)

2006

Interest &

Dilution

0.27

Planned

Outag es

0.20

Inflation

(0.08)

Product

-iv ity

0.22 Gas

Plant

EBIT

Ex: HD

(0.13) PPA 's

(0.04)

CTC

(0.14)

M id-A tlantic

Fleet

0.92

Other

0.03

Competitive

Supply

$3.25

$3.75

$4.25

$4.75Generation

OtherProductivity &

Inflation

This is the waterfall projection for 2007 vs. 2006 that we shared with you in January 2007. The bottom of the slide compares our actual performance to what we told you to expect in January. Overall, we were higher than forecast by 12 cents, primarily driven by improved performance in Competitive Supply and BGE as well as favorable interest and dilution.

75

75

Wholesale Competitive Supply

New Business

(5)%(35)682647Total New Business Realized

11434445Portfolio Management & Trading

3%$34$983$1,016Total Contribution Margin

(46)248202Originated & Realized

23%$68$301$369Total Already Originated Business

%$FY 2006FY 2007Change($ in millions)

We realized just over $1 billion of Wholesale Competitive Supplycontribution margin in 2007. As you can see in the top line, $369 million came from already originated business and $647 million came from new business realized.

76

76

Merchant – Q4 Income Statement

See Appendix

(1) Earnings excluding special items, certain economic, non-qualifying hedges, and synfuel earnings(2) Includes $27M and $30M of nuclear fuel amortization for Q4 ’06 and Q4 ’07, respectively

(2%)$ (5)$ 235$ 230Mid Atlantic Fleet

7%9124133PPA

(18%)(2)119QF/Other

37%101273374Wholesale Competitive Supply

44%52119171Retail Competitive Supply

(30%)(18)(60)(78)D & A (2)

45%$ 72$ 161$ 233Net Income

(40%)(42)(104)(146)Income Tax

43%114265379Pre-Tax Income

48%16(33)(17)Net Interest Expense

33%98298396EBIT

(12%)(57)(464)(521)Total Costs below Gross Margin

8

(47)

155

$

Change

32%

(12%)

20%

%

(25)(17)Other Revenue and Expenses

(379)(426)O & M

762917Gross Margin (2)

Q4 2006(1)Q4 2007(1)($ in millions)

Overall, Merchant gross margin increased by $155 million from Q42006 to Q4 2007 driven by favorable results in the Competitive Supply businesses. In Retail Competitive Supply, New Energy Electric's performance was up due to the continued trend of strong realizedmargins and New Energy Gas was up primarily due to MTM gains in Q4 2007 as prior period mark-to-market losses reversed. Wholesale Competitive Supply was up due to higher backlog and new businessrealizations.

Expenses were unfavorable ($57) million, primarily due to highercosts to support growth and inflation. These increases were offset by lower costs due to the absence of the Ginna outage in 2006.

Net Interest expense was favorable $16 million primarily due to a larger cash balance and higher short-term interest rates.

In the end, Merchant net income was favorable $72 million.

77

77

Merchant – 2007 Income Statement

(1) Earnings excluding special items, certain economic, non-qualifying hedges, and synfuel earnings(2) Includes $98M and $114M of nuclear fuel amortization for ’06 and ’07, respectivelySee Appendix

32%$ 249$ 786$ 1,035Mid Atlantic Fleet

5%30574604PPA

(4%)(2)5351QF/Other

8%861,0401,126Wholesale Competitive Supply

24%80340420Retail Competitive Supply

(10%)(26)(257)(283)D & A

42%$ 203$ 485$ 688Net Income

36%(115)(318)(433)Income Tax

40%3188031,121Pre-Tax Income

64%109(169)(60)Net Interest Expense

22%2099721,181EBIT

(13%)(234)(1,821)(2,055)Total Costs below Gross Margin

7

(215)

443

$

Change

7%

(15%)

16%

%


(1,465)(1,680)O & M

2,7933,236Gross Margin (2)

2006 (1)2007 (1)($ in millions)

Overall, Merchant gross margin increased by $443 million from 2006 to 2007. Mid-Atlantic Fleet gross margin was the primarily driver due to the roll-off of below market hedges partially offset by the end of the Competitive Transition Charge. The Plants with PPA's were up primarily due to the Ginna uprate and both the Mid-Atlantic and Plants with PPA'ssaw the favorable impact of fewer planned outage days. In RetailCompetitive Supply, New Energy Electric's performance was up due to the continued trend of strong realized margins which was partially offset by mark-to-market losses at New Energy Gas. Wholesale Competitive Supply was up due to higher backlog realization.

Expenses were unfavorable ($234) million primarily due to highercosts to support growth and inflation. These increases were partially offset by lower costs due to the sale of the gas plants in December 2006, and the absence in 2007 of the Ginna outage.

Net Interest expense was favorable $109 million due to higher cash balances.

In the end, Merchant net income was favorable $203 million.

78

78

2007 Segment Cash Flow

See Appendix

309-21Asset Disposition & Contract Restructuring

(33)---Pension Adjustment (pre-tax)

(273)33(118)(155)Operating Cash Flow

($1,159)

(306)

(344)

(509)

(266)

(96)

(965)

(1,717)

752

$ 821

Total

-(266)-SB1 Rate Deferral

Equity – Benefits Plans

9257486Depreciation & Amortization

$ 12$ 130$ 679Net Income

26(46)(76)Working Capital & Other

Net Cash Flow before Debt Issuances/(Payments)

Dividends

42(384)(134)Free Cash Flow

(5)(202)(758)Net CapEx

(14)(459)(1,244)Capital Expenditures / Investments

Other Non-RegUtilityMerchant($ in millions)

This slide shows our 2007 cash flow broken out into our Merchant, Utility and Other Non-Regulated businesses. Our net cash flow before debt issuances or payments was a use of $1.2 billion. When looking at the specific segments, we see that the Merchant business had a free cash flow of ($134) million, driven mostly by capital expenditures/ investments. Our Utility business had a free cash flow of ($384) million driven by capital expenditure/investments and rate deferrals. Our Other Non-Regulated business had free cash flow of $42 million driven by working capital and net income.

79

79

Excess Liquidity

At the end of December, the Company had $3.8 billion in excess liquidity

$ in

Bill

ions

Cash And Bank Lines Bank Line Usage

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

31-D

ec-01

31-D

ec-02

31-D

ec-03

31-D

ec-04

31-D

ec-05

31-M

ar-06

30-Ju

n-06

30-S

ep-06

31-D

ec-06

31-Ja

n-07

28-Feb

-07

30-M

ar-07

30-A

pr-07

31-M

ay-07

30-Ju

n-07

31-Ju

l-07

31-A

ug-07

30-S

ep-07

31-O

ct-07

30-N

ov-07

31-D

ec-07

Excess Liquidity

This chart shows our excess liquidity, which was $3.8 billion at the end of 2007. The top blue line represents our cash balances plus our bank lines, the total of which was approximately $5.6 billion at the end of the year. The tan line on the bottom of the chart shows our bank line usage as we post letters of credit with counterparties. At the end of 2007, we had posted about $1.8 billion in LC’s. This chart illustrates Constellation Energy’s continuous ability to access capital as our business has grown, maintaining a prudent liquidity position.

80

80

Synfuel Update

(110)(44)Current period credit phase-out

$0.16$30

($34)-

$1038%

$6412034

($90)

2006 Actual

($0.02)($4)($96)

-

$1470%

$9216643

($117)

2007 Actual

Tax credit phase-out percentage

Net synfuel EPSNet synfuels income

Production expenses, net of tax

Impact of phase-out

Pre-phase-out:

Net income impact of phase-outPhase-out catch-up prior quarters

Net income pre-phase-outTax credits before phase-outTax benefit of pre-tax lossPre-tax loss on production

($ in millions, except per share amounts)

The federal tax credit for synthetic fuel produced from coal expired December 31, 2007Note: Numbers may not add due to rounding

With the expiration of the federal tax credit produced from coal on December 31, 2007, this chart provides our final update of synfuel earnings, which have been excluded from adjusted earnings throughout the presentation.

Our synfuel facilities generated an overall net loss of $4 million or ($0.02) per share in 2007 compared to $30 million of net income in 2006. The decrease in net income is a result of an increase in the estimated tax credit phase-out of 70% in 2007 compared to 38% in 2006.

The actual phase-out will not be known until published by the IRS in March/April, 2008. A final true-up of 2007 synfuel earnings may be necessary at that time.

81

81

South Carolina Synfuel


3.52.7Production (tons in millions)


$0.09$16

($25)-

$338%

$407623

($59)

2006 Actual

($0.03)($5)($66)

-

$970%

$6111231

($82)

2007 Actual




Impact of phase-out

Pre-phase-out:




This chart shows the individual contribution of the South Carolina facility to overall synfuel operating results. Overall, our 2007 net synfuel loss for the South Carolina facility was (3) cents per share.

82

82

Pace Synfuel


1.71.4Production (tons in millions)


$0.08$14($9)

-

$738%

$244411

($32)

2006 Actual

$0.01$1

($31)-

$570%

$325412

($35)

2007 Actual




Impact of phase-out

Pre-phase-out:




This chart shows the individual contribution of the Pace facilities to overall synfuel operating results. Overall, our 2007 net synfuel earnings for the Pace facilities was 1 cent per share.

83

83

Additional Modeling

• CEG Financial Results

• CEG Financial Outlook

– Forward Market Data Used in Outlook p. 84

– Merchant Income Statement p. 85

– Cash Flow p. 87

• Customer Supply


• Generation

• BGE

84

84

Forward Market Data Used in Outlook (12/31/07)

201020092008

67.4266.4261.93PJM WHUB ($/MWh) (7 x 24)

64.6064.6360.00NY West Zone ($/MWh) (7 x 24)

59.6059.0456.75NYMEX Coal ($/Ton)

$8.39$8.28$7.52NYMEX Gas ($/MMBtu)

The above market prices are indicative of the prices used in ouroutlook.

85

85

Merchant – 2008E Income Statement

See Appendix

(1) Represents the mid-point of earnings guidance range(2) Earnings excluding special items, certain economic, non-qualifying hedges, and Synfuel earnings (3) Includes $114M and $120M of nuclear fuel amortization for ’07 and ’08, respectively(4) Preliminary view of recast historical information(5) Includes ($2M) equity in earnings for UniStar Nuclear Energy

30%229(4)

756985Global Commodities Group

(8%)(63)(4)

800737Customer Supply

16%$266 (4)$ 1,680$ 1,946Generation

(19%)(55)(283)(338)D & A

27%$ 184$ 688$ 872Net Income29%(125)(433)(558)Income Tax

28%3091,1211,430Pre-Tax Income(50%)(30)(60)(90)Net Interest Expense

29%3391,1811,520EBIT(4%)(91)(2,055)(2,146)Total Costs below Gross Margin

(8)

(28)

430

$

Change

(5)

(9%)

(2%)

13%

%


(1,680)(1,708)O & M

3,2363,666Gross Margin (3)

2007 (2)2008E (1) (2)($ in millions)

Overall, Merchant gross margin is expected to increase by $430 million from 2007 to 2008. Generation is estimated to be up due to the continued roll-off of lower priced hedges and higher capacity prices. Customer Supply gross margin is expected to be down slightly due to lower wholesale backlogs and the return of retail power margins to more normal levels following a very strong 2007, partially offset by favorable results at Retail Gas as the business returns to normal operations. Global Commodities gross margin is forecast to be favorable due to higher backlogs.

Expenses are estimated to be up ($91) million primarily due to higher costs to support growth, inflation, and the impact of higher capital investment. Net Interest expense will also be higher due primarily to higher capital investment.

In the end, Merchant net income is expected to be favorable $184million.

86

86

Merchant – 2008E EBIT

38512614245Add: Depreciation & Amortization

$ 2,116$ 567$ 456$ 1,093EBITDA

(170)Unallocated Corporate Costs (2)

1,731441442848EBIT

$ 1,946Total Merchant EBITDA

(1,935)(544)(295)(1,098)Less: Operating Expenses (1)

$ 3,666$ 985$ 737$ 1,946Gross Margin

Global Commodities

Total Merchant

Customer SupplyGeneration($ in millions)

Note: May not add due to rounding(1) Excludes allocation of corporate costs and includes upstream gas operating expenses of $158M in Global Commodities.(2) Not allocated below Merchant and excludes depreciation & amortization(3) Includes ($2M) equity in earnings for UniStar Nuclear EnergySee Appendix

(3)

Total Merchant EBITDA for 2008 is projected to be approximately $1.9 billion, primarily consisting of $1.1 billion in Generation, $456 million in Customer Supply, and $567 million in Global Commodities.

87

87

Consolidated Cash Flow

206301,750866Asset Dispositions & Contract Restructuring

(419)(273)(124)(305)Operating Cash Flow(6)(33)3316Pension Adjustment (pre-tax)

55(266)(326)-SB1 Rate Deferrals

($529)($1,159)$ 1,120$ 429Net Cash Flow before Debt Issuance / (Payments)

(306)(344)(509)

(96)(965)

(1,717)752

$ 8212007

(34)8497Equity – Benefits Plans

799714700Depreciation & Amortization$ 1,009$ 936$ 625Net Income

75(728)(570)Working Capital & Other

(337)(264)(229)Dividends

(158)1,300561Free Cash Flow

(1,497)(365)(376)Net CapEx(2,296)(1,079)(1,076)Capital Expenditures / Investments

2008E20062005($ in millions)

See Appendix

This slide shows the historical cash flow for the consolidated company

for 2005 through 2007 along with the forecasted cash flow for 2008. For

2008 we are forecasting net cash flow before debt issuances or payments

of ($529) million. These numbers are all driven by strong net income

growth, offset by growth in capital expenditures and investments.

88

88

2007 and 2008E Capital Expenditures

($2,296)2008 Capital Expenditures (Slide 61 & 87)

($ in millions)

34BGE Cost of Removal

32Repayments of Loans Receivable

(1)Other

86Other Investing – Restricted Cash

($2,448)2008 Capital Expenditures (Slide 58)

Note: Numbers may not sum due to rounding

($1,717)2007 Capital Expenditures (Slide 77 & 87)

(110)Other Investing – Restricted Cash

25BGE Cost of Removal

45Repayments of Loans Receivable

($ in millions)

(19)Payments for issuance of Loans Receivable

7Other

($1,665)2007 Capital Expenditures (Slide 58)

This chart represents the walk between Total Capital Spending for 2007 and 2008 on Slide 58 and the Capital Expenditures shown in the Cash Flows noted on this slide.

89

89

2007 and 2008E Depreciation and Amortization

$ 7992008 D&A (Slide 61 & 87)

1Other

($ in millions)

68ARO Liability

-Synfuel Amortization Adjustment

120Nuclear Fuel Amortization

$ 6102008 D&A

$ 7522007 D&A (Slide 77 & 87)

11Other

($ in millions)

68ARO Liability

20Synfuel Amortization Adjustment

114Nuclear Fuel Amortization

$ 5382007 D&A

Note: Numbers may not sum due to rounding

This chart represents the walk between Total Depreciation and Amortization for 2007 and 2008 and the Depreciation and Amortization shown in the Cash Flows noted on this slide.

90

90

Additional Modeling

• Financial Results

• Financial Outlook

• Customer Supply

– Customer Supply Performance Metrics p. 91


• Generation

• BGE

91

91

Customer Supply (Retail Power) – Performance Metrics

Delivered Volume (MWh)

10

30

50

70

90

2004 2005 2006 2007 2008E

Realized Electric Gross Margin (GM / MWh)

$1.00

$3.00

$5.00

$7.00

4Q05 3Q06 2Q07 2008E

Retention Rates

50%

75%

100%

4Q061Q07

2Q073Q07

4Q07200

8E

Including Return to Utility Excluding Return to Utility

The retention rate, representing the percentage of our customers up for renewal that re-sign with us, was 68% in 2007. Excluding customers returning to utility service, our retention rate was over 70%. This is in line with historical trends, and we expect the retention rate in 2008 to be 75% to 80%.

In 2007, realized electric gross margin was $5.28 per megawatt hour, driven primarily by lower costs to serve customers. The forecast for 2008 is $3.80 per megawatt hour, as we expect new business and costs to serve to revert to historical levels.

In 2007, electric volumes were 73 million megawatt hours up 7% versus 2006, driven primarily by volume growth in sales. Looking ahead to 2008, we plan to deliver 80 million megawatt hours.

92

92

Customer Supply (Retail Gas) – Performance Metrics

Annual Load Volume (Bcf)

100

200

300

400

500

600

2005 2006 2007 2008E

Retention Rates

80%

90%

100%

3Q06 1Q07 3Q07 2008E

Realized Gas Gross Margin (GM / Dth)

$0.00

$0.10

$0.20

$0.30

3Q05 1Q06 3Q06 1Q07 3Q07 2008E

In our retail gas business, the 2007 retention rate was 94%, in line with the prior year rate of 95%. In 2008, we expect to maintain retention rates in the 90% to 95% range.

In 2007, realized gross margin was $0.17 per decatherm, while the forecast for 2008 is $0.20 per decatherm.

In 2007, delivered gas volumes were 410 Bcf, up 16% versus 2006 reflecting both organic growth and acquisitions. Looking ahead to 2008, we plan to deliver 491 Bcf.

93

93

Additional Modeling• Financial Results


• Customer Supply

• Global Commodities Group

– Upstream Gas Assets p. 94

• Generation

• BGE

94

94

Upstream Gas Assets

• Portfolio represents 355 bcfe of proved reserves (including CEP)• Current daily production over 67 MMcfe per day (including CEP)

Black Warrior Basin CBM (AL)Cherokee Basin CBM (OK/KS) (3)Woodford shale (OK) (2)Gulf Coast CBM (LA)South Texas tight sandsWyoming tight sandsFayetteville shale (AR)Ohio shaleOklahoma dewateringWest Virginia CBMWilliston Basin shale (MT)Shallow GOM (AL) South East Texas carbonates

Current Portfolio of Investments

Constellation Energy Partners Unconventional Conventional

We are developing E&P projects in various locations with a majority of unconventional production, including coalbed methane, tight sands and shale. At the end of 2007, we owned nine producing assets totaling 355 Bcfe of proved reserves and generating daily production of approximately 67 MMcfeper day.

The growth strategy for Constellation Energy’s upstream gas business continues to be invest, develop and harvest, and an important part of that strategy is the potential for dropdown transactions with Constellation Energy Partners. We are committed to growing our upstream portfolio and to monetize maturing investments through dropdowns or third party transactions after enhancing their value.

Our portfolio has a potential to yield long-lived stable cash flows. We estimate that it typically takes 3 to 5 years to progress from early stage to mature stage. Constellation Energy Partners (CEP) is an important partner in our oil and gas investment strategy. Their investment criteria require mature, producing properties. Given the stage of development of some of our assets, we see the potential to drop down an asset to Constellation Energy Partners within the next 12 months.

95

95



• Customer Supply


• Generation

– Plant Statistics p. 96

– Fuel Mix p. 98

– Nuclear PPA Plants p. 99

– Environmental Capex p. 100

– Potential Impact of Carbon p. 101

• BGE

96

96

Plant StatisticsInstalled Capacity

(MW)% Owned

Capacity Owned (MW)

Primary Fuel

Plant Location

Brandon Shores Anne Arundel Co., MD 1,286 100.0% 1,286 CoalC. P. Crane Baltimore Co., MD 399 100.0% 399 Oil/CoalCalvert Cliffs Calvert Co., MD 1,735 100.0% 1,735 NuclearConemaugh Indiana Co., PA 1,711 10.6% 181 CoalH. A. Wagner Anne Arundel Co., MD 963 100.0% 963 Coal/Oil/GasHandsome Lake Rockland Twp, PA 268 100.0% 268 GasKeystone Armstrong and Indiana Cos., PA 1,711 21.0% 359 CoalNotch Cliff Baltimore Co., MD 120 100.0% 120 GasPerryman Harford Co., MD 355 100.0% 355 Oil/GasPhiladelphia Road Baltimore City, MD 64 100.0% 64 OilRiverside Baltimore Co., MD 232 100.0% 232 Oil/GasSafe Harbor Safe Harbor, PA 417 66.7% 278 HydroWestport Baltimore City, MD 116 100.0% 116 GasTotal Mid Atlantic Region 9,376 6,355

Ginna Ontario, NY 581 100.0% 581 NuclearNine Mile Point Unit 1 Scriba, NY 620 100.0% 620 NuclearNine Mile Point Unit 2 Scriba, NY 1,138 82.0% 933 NuclearTotal Plants with Power Purchase Agreements 2,339 2,134

ACE Trona, CA 102 31.1% 32 CoalChinese Station Jamestown, CA 20 45.0% 9 BiomassColver Colver Township, PA 104 25.0% 26 Waste CoalMalacha Muck Valley, CA 32 50.0% 16 HydroMammoth Lakes G 1 Mammoth Lakes, CA 6 50.0% 3 GeothermalMammoth Lakes G 2 Mammoth Lakes, CA 13 50.0% 7 GeothermalMammoth Lakes G 3 Mammoth Lakes, CA 13 50.0% 7 GeothermalPanther Creek Nesquehoning, PA 80 50.0% 40 Waste CoalRio Bravo Fresno Fresno, CA 24 50.0% 12 BiomassRio Bravo Jasmin Kern Co., CA 35 50.0% 18 CoalRio Bravo Poso Kern Co., CA 35 50.0% 18 CoalRio Bravo Rocklin Placer Co., CA 24 50.0% 12 BiomassSEGS IV Kramer Junction, CA 33 12.2% 4 SolarSEGS V Kramer Junction, CA 24 4.2% 1 SolarSEGS VI Kramer Junction, CA 34 8.8% 3 SolarSoda Lake I Fallon, NV 4 50.0% 2 GeothermalSoda Lake II Fallon, NV 10 50.0% 5 GeothermalSunnyside Sunnyside, UT 51 50.0% 26 Waste Coal

644 239

Total Generating Facilities 12,359 8,728

Other

Total Other

(at December 31, 2007)

Mid Atlantic Region

Plants with Power Purchase Agreements

This chart shows a summary of our Generation plant statistics.

97

97

Generation Assets – 8,728 MW as of December 2007

Rocklin (QF)12 MW

Biomass

Fresno (QF)12 MW

Biomass

Poso (QF)17 MW, Coal

Jasmin (QF)17 MW, Coal

Panther Creek (QF)40MW, Waste Coal

Safe Harbor (EWG)278 MW, Hydro

Baltimore Plants3503 MW Coal, Gas, Oil

Malacha (QF)16 MW, Hydro

A/C Fuels

PC V. I

PC WV. I

PC WV. II

PC WV. III

Fuel Processing Plant

Western Plants

Nuclear Plants

Eastern Plants

Calvert Cliffs1,735 MW Nuclear

Sunnyside (QF)26 MWWaste Coal

Chinese Station (QF)10 MW, Biomass

Mammoth Lakes G-1,2,3 (QF)15 MW, Geothermal

ACE(QF)32 MW, Coal

SEGS IV,V,VI (QF)8 MW, Solar

Handsome Lake268 MW, 5 CTs, Gas

Colver (QF)26 MW

Waste Coal

Keystone (EWG)357MW, Coal

2 MW Oil

Conemaugh (EWG)180 MW, Coal

1 MW Oil

Soda Lake (QF)7 MW, Geothermal

Gary PCI

Nine Mile Point1,553 MW Nuclear

R.E. Ginna 581 MW Nuclear

Baltimore PlantsBrandon Shores 1, 2 1,286 MW CoalWagner 1-4, CT 459 MW Coal (2,3)

126 MW Gas/Oil (1)364 MW Oil (4)

14 MW Oil CTCrane 1, 2, CT 385 MW Coal (1,2)

14 MW Oil CTRiverside 4, 6, 7, 8 78 MW Gas Steam (4)

115 MW Gas/Oil CT (6)39 MW Oil CT (7,8)

Westport 5 116 MW Gas CTPhiladelphia Rd. 1-4 64 MW Oil CTNotch Cliffs 1-8 120 MW Gas CTPerryman 1-4, 51 208 MW Oil CT (1-4)

147 MW Gas/Oil CT

Rocklin (QF)12 MW

Biomass

Fresno (QF)12 MW

Biomass

Poso (QF)17 MW, Coal

Jasmin (QF)17 MW, Coal

Panther Creek (QF)40MW, Waste Coal

Safe Harbor (EWG)278 MW, Hydro

Baltimore Plants3503 MW Coal, Gas, Oil

Malacha (QF)16 MW, Hydro

A/C Fuels

PC V. I

PC WV. I

PC WV. II

PC WV. III


Western Plants

Nuclear Plants

Eastern Plants


Western Plants

Nuclear Plants


Western Plants

Nuclear Plants

Eastern Plants

Calvert Cliffs1,735 MW Nuclear

Sunnyside (QF)26 MWWaste Coal

Chinese Station (QF)10 MW, Biomass

Mammoth Lakes G-1,2,3 (QF)15 MW, Geothermal

ACE(QF)32 MW, Coal

SEGS IV,V,VI (QF)8 MW, Solar

Handsome Lake268 MW, 5 CTs, Gas

Colver (QF)26 MW

Waste Coal

Keystone (EWG)357MW, Coal

2 MW Oil

Conemaugh (EWG)180 MW, Coal

1 MW Oil

Soda Lake (QF)7 MW, Geothermal

Gary PCI

Nine Mile Point1,553 MW Nuclear

R.E. Ginna 581 MW Nuclear

Baltimore PlantsBrandon Shores 1, 2 1,286 MW CoalWagner 1-4, CT 459 MW Coal (2,3)

126 MW Gas/Oil (1)364 MW Oil (4)

14 MW Oil CTCrane 1, 2, CT 385 MW Coal (1,2)

14 MW Oil CTRiverside 4, 6, 7, 8 78 MW Gas Steam (4)

115 MW Gas/Oil CT (6)39 MW Oil CT (7,8)

Westport 5 116 MW Gas CTPhiladelphia Rd. 1-4 64 MW Oil CTNotch Cliffs 1-8 120 MW Gas CTPerryman 1-4, 51 208 MW Oil CT (1-4)

147 MW Gas/Oil CT

This chart provides a view of our generation assets. As you can see, we maintain assets primarily in the Mid-Atlantic region and California. This chart also shows you the capacity of each asset and fuel type.

We have 78 units representing 8,728 megawatts of primarily base-load nuclear and coal generating capacity. Assets are located in high value markets like PJM and New York.

98

98MMWh51.8Total

MMWh1.9Other

MMWh32.0Nuclear

MMWh0.2Gas

MMWh17.8Coal

CEG 2008E

Fuel Mix

MW8,728Total

MW1,544Other

MW3,869Nuclear

MW582Gas

MW2,733Coal

2007CEG

MW8,728TotalMW1,544Other

MW3,869Nuclear

MW582Gas

MW2,733Coal

2008ECEG

MMWh51.6Total

MMWh2.1Other

MMWh31.6Nuclear

MMWh0.2Gas

MMWh17.8Coal

2007CEG

Coal, 31%

Gas, 7%Nuclear,

44%

Other, 18%

Coal, 31%

Gas, 7%Nuclear,

44%

Other, 18%

Coal, 34%

Gas, 0%Nuclear, 61%

Other, 4%Coal, 34%

Gas, 0%Nuclear, 62%

Other, 4%

Owned Capacity

Generation

(1)


These charts show the fuel mix of our owned generation assets. As you can see, our primary fuels are 44% nuclear and 31% coal based on capacity, and 61% nuclear and 34% coal based on output.

99

99

Nuclear PPA Plants

(1) After termination of PPA, revenue sharing agreements in place with former owners through 2021

83 MW uprate completed in 2006 105 MW uprate to be completed in 2010 Other

June 2014Unit 1: August 2009Unit 2: November 2011

Contracted Through:

4.714.4TWh (100%)

PPA:• Long-term unit contingent agreement

to sell owned energy and capacity to RG&E at average price of $44/MWh

• Until Spring 2008, sell approx. 80% of energy and capacity to RG&E and thereafter approx. 85%.

PPA:• Long-term unit contingent agreements to sell

approximately 90% of owned energy and capacity to former owners at average price of $35/MWh

Revenue Sharing Agreement on Unit 2 (1):• Strike price averages $40.75 for first year of

Revenue Sharing Agreement (RSA) and escalates at 2% per year thereafter

• Market prices exceeding strike price trigger revenue sharing – 80% to former owners, 20% to CEG

Contract Terms

100% OwnedUnit 1: 100% OwnedUnit 2: 82% Owned

Ownership

581 MWUnit 1: 620 MWUnit 2: 1,138 MW

Unit Capacity (100%)

GinnaNine Mile Point

As you’ll recall, our portfolio of Nuclear PPA Plants consists of two units with 1,553 MW of combined owned capacity at our Nine Mile Point plant and one unit with 581 MW capacity at our Ginna plant, which includes additional capacity of the 83 MW from the uprate completed in 2006.

For Nine Mile Point Unit 1, we sell approximately 90% of the energy and capacity to the former owners at nearly $35 per megawatt-hour until August 2009. For our 82% share of Nine Mile Point Unit 2, we sell about 90% of the energy and capacity to the former owners at nearly $35 per megawatt hour until 2011. For a 10-year period following the end of the current PPA for Nine Mile Point Unit 2, we share the benefits of prices above a defined strike price, approximately 80% to the former owners and 20% to CEG. The defined strike price averages $40.75 per megawatt hour for the first year of the RSA, then escalates at 2% per year thereafter.

For Ginna, we have agreed to sell energy and capacity to RG&E at an average price of $44 per megawatt-hour. With the completion of our 83 MW uprate in November 2006, we sell approximately 80% of Ginna’s energy and capacity to RG&E through Spring of 2008, and approximately 85% until the PPA ends in 2014.

100

100

Environmental Capex

1,14363267466329$17Prior Projections (1/07)

$1,119$62$335$548$157$17Current Estimate

-

2006

172 241(68)(82)Change

2007 Total2010+20092008($ in millions)

Note: Excludes capitalized interest; Numbers may not add due to rounding

This chart shows you the breakout of our projected environmentalcapex for Brandon Shores, Wagner and Crane to comply with the Maryland Healthy Air Act by 2010, as well as our share of spending at the Keystone plant in Pennsylvania. While the timing of spend has shifted from 2007 into 2008 and 2009, our current spend projection of $1.1 billion is similar to the guidance we provided in January 2007.

101

101

Mid-Atlantic Assumptions

• ~42% of time coal on

the margin

• ~55% of time gas on the margin

• ~14,000 GWhs in Nuclear Portfolio

• ~13,500 GWhs in Coal PortfolioC

hang

e in

Gro

ss M

argi

n ($

milli

ons)

Carbon Value

Carbon Credit ($/ton)

Potential Impact of Carbon

Cha

nge

in P

ower

($/M

Wh

)

$0

$75

$150

$225

$300

$375

$450

$5 $10 $15 $20 $25 $30 $35 $40 $45 $500

10

20

30

40

50

60

This slide gives an indication of how the different values for carbon could potentially impact Constellation Energy’s gross margin. The analysis looked at the potential average gross margin increase over a five year period (2008-2012) and includes the value derived by our nuclear generation, offset by the value absorbed by our coal generation over a 7x24 generating basis.

102

102



• Commodities

• NewEnergy

• Generation

• BGE

– Overview p. 103

– 2008E BGE Income Statement p. 104

– Gross Margin p. 105

– 2008 Electric T&D Overview p. 106

– Gas Delivery p. 108

– Rate Base & ROE p. 109

103

103

Baltimore Gas & Electric OverviewBaltimore Gas & Electric (BGE)

8.1%ROE

24th

13th

Industry rank (by # of customers)- Electric distribution- Gas distribution

Maryland PSCFERC

Regulators- Electric & gas distribution- Electric transmission

Long-term volume growth (customer & usage)

2007 Net income ($ millions)

2007 Rate base ($ billions)

Gas customers (millions)

Electric customers (millions)

1% - 2%

$134.8

$3.2

0.6

1.2

Service Area – Central Maryland

Modest long-term growth in number of customers and customer usage

Baltimore Gas & Electric serves 1.2 million electric customers and 600,000 gas customers in central Maryland. In terms of number of customers served, BGE’s electric distribution business ranks 24th out of 97 companies with customers of 250,000 or more. BGE’s gas distribution business ranks 13th out of 45 companies with at least 100,000 customers.

In 2007, BGE had a rate base of approximately $3 billion and generated $134.8 million of net income, which translated into a ROE of about 8.1%. BGE should experience modest long-term volume and usage growth.

BGE’s electric and gas distribution businesses are regulated by the Maryland Public Service Commission.

104

104

2008E BGE Income Statement

1(88)(87)Income Tax

7337344EBIT1(173)(172)Other Expenses

(15)(246)(261)D & A

($ 0.04)$ 0.74$ 0.70Adjusted EPS (1)

($8)$ 135$ 127Net Income-(13)(13)Preferred Dividends

(16)(101)(117)Net Interest Expense

(15)(522)(537)O & M

4323327Gas Gross Margin

361,2781,314Gross Margin

$ 32$ 955$ 987Electric Gross Margin

Change20072008E (1)($ in millions except per share data)

Major Variance Drivers vs. 2007 +2¢ Customer Growth (7¢) Interest, Accretion and D&A +3¢ Transmission Revenue (8¢) O&M and Other Expenses +6¢ Demand Response, Gas and other Revenue

(1) Represents mid-point of guidance rangeSee Appendix

BGE electric gross margin is expected to be higher by $32 million in 2008, primarily driven by customer growth, transmission revenues, and demand response revenues. In 2008, BGE implemented decoupling for electric distribution which will result in more stable revenues for the distribution business by normalizing out weather variations and use per customer variations arising from energy conservation programs. BGE gas margins are expected to be higher by $4 million in 2008 due to higher distribution revenue driven by customer growth and higher reliability charges. In total, gross margin is expected to be up $36 million.

We expect to increase our expenses by $29 million in 2008 versus2007. The increase is driven by higher operational costs and depreciation and amortization expenses. We also expect higher interest expenses due to higher average debt in 2008.

We project the 2008 earnings per share at the utility to be 70 cents per share, down 4 cents from 2007.

105

105

BGE Gross Margin

See Appendix

$1,278$1,320Total Gross Margin323327Gas Margin955993Electric Gross Margin

(2,140)(2,582)Total Cost of Goods Sold(640)(632)Gas Purchased for Resale

(1,500)(1,950)Electricity Purchased for Resale

3,4183,902Total Regulated Revenue963959Gas Revenue

$2,455$2,943Electric Revenue

20072008E($ in millions)

In 2008, we expect to generate $3.9 billion in total regulated revenue, an increase of 14% over 2007. Of this amount, $2.9 billion will be from electric revenue due to higher commodity prices and $1.0 billion will be from gas.

Our cost of goods sold is expected to be approximately $2.6 billion with electricity purchased for resale increasing 30% due to the expiration of price caps. Gas purchased for resale in 2007 is expected to decrease 1% due to lower natural gas prices.

Electric gross margin is expected to increase 4% from 2007, and gas gross margin is expected to increase 1%. Overall, total gross margin is expected to be 3% higher compared to 2007.

106

106

BGE 2008 Electric T&D Overview

32,961,8121,234,108Total

23.90630,82074760-599 KW

35.39102,6134,5740-59 KW

13.572,726,148121600+ KW

Industrial

15.316,588,985524600+ KW

25.116,218,3449,65560-599 KW

33.493,410,903107,7770-59 KW

Commercial

$34.2213,283,9991,110,710Residential

2008 T&D / MWh Rates

2008 WeatherNormalized MWh (MM)CustomersCustomer Class

In 2008, we expect to serve 1.2 million customers approximately 33 GWh of electricity. Of these customers, approximately 90% are residential with the remaining 10% comprised of commercial and industrial.

107

107

BGE Electric T&D Quarterly Profile

Excludes Special Items- See Appendix

$458.6n/a32,961,8122008E

Cooling weather was favorable at 9.5% warmer than normal. Heating weather was unfavorable at 2.7% milder than normal.

$442.3186,02433,112,454Total

Weather was driven by a very warm October. Q4 was 221% warmer than normal (CDD), partially offset by 7.7% milder than normal (HDD).

101.277,7417,774,596Q4

Weather was 1.4% warmer than normal in August & September, offset by a mild July.

123.26,4729,092,887Q3

Weather was 9.5% colder in April. May & June were 7.5% warmer.98.2123,9907,779,125Q2

Weather was 0.8% milder than normal.$119.7(22,179)8,465,846Q1

2007Comments/Drivers

EBITDA (million)

MWhs vs. Normal WeatherMWhsPeriod

For 2007, EBITDA was $442.3 million with favorable cooling weather at 9.5% warmer than normal.

In 2008, assuming a return to normal weather, we expect EBITDA to increase by $16 million primarily due to increased net revenues, partially offset by higher operating expenses.

108

108

BGE Gas Delivery Quarterly Profile

$10.3$126.1655,5422008E

$11.2$128.4Total 2007

3.539.0646,179Q4

1.21.7643,626Q3

0.911.9643,170Q2

$5.6$75.8643,608Q1

2007

Gains from Cost Sharing

(millions)EBITDA (1)

(millions)CustomersPeriod

(1) EBITDA excluding off-system sales and special itemsSee Appendix

This slide details our gas delivery profile for 2007 by quarter and provides an estimate for full year 2008 gas delivery. In 2007, gas delivery contributed $128.4 million of EBITDA. For 2008, EBITDA from gasdelivery is expected to be $126.1 million.

There are two programs from which BGE receives gains from sharing costs. The Market Based Rates program approved by the PSC provides BGE financial incentives to seek lower-priced gas for its customers. The Off-System Sales program allows BGE to bundle its unused pipeline capacity with the natural gas commodity to make a delivered sale directly with a purchaser outside of BGE’s market. Gains achieved through the cost sharing programs were $11.2 million in 2007 and are estimated to be $10.3 million in 2008.

109

109

2007 BGE Rate Base

$ 368$ 820$ 2,061Total Rate Base

(333)(607)(1,972)Deductions from Rate Base

4113145Additions to Rate Base

$ 697$ 1,314$ 3,888Utility Plant

TransmissionGas

DistributionElectric

Distribution($ in millions)

For 2007, our total rate base was $2 billion from electric distribution, $820 million from gas distribution, and $368 million related to transmission.

110

110

BGE ROE

(1) Includes actual gas rate case of $35.6 million (2) Excludes Special Item

Regulated & Book ROE

8.1%9.7%11.4%BGE Book ROE

7.1%10.0%11.0%BGE Regulated ROE

10.7%10.7%10.8%Regulated Electric Transmission

6.7%9.6%11.0%Blended Distribution

5.8%8.7%5.3%Regulated Gas Distribution

7.1%9.7%13.6%Regulated Electric Distribution2007(1)(2)2006(1)(2)2005

In 2007, BGE regulated ROE was 7.1% and Book ROE was 8.1%, slightly lower than BGE’s ROE in 2005 and 2006.

Regulated ROE does not include BGE Electric POLR return or gainsfrom its Gas cost sharing program. For the three years shown, these additional after-tax net income amounts were:

Electric POLR Gas Sharing

2005 $10.5M $6.4M

2006 $14.3M $6.0M

2007 $13.0M $6.8M

111

Non-GAAP Appendix

112

112

Summary of Non-GAAP Measures

Slide(s) Where Used Slide Containing Non-GAAP Measure in Presentation Most Comparable GAAP Measure Reconciliation

Adjusted EPS Reported GAAP EPSYTD 2007 Actual 5, 49, 51, 56, 57, 66, 72, 74 113YTD 2006 Actual 51, 66, 72, 74 113YTD 2005 Actual 66, 72 114Q407 Actual 49, 50 115Q406 Actual 50 115Q107 Actual 64 1172007 and 2006 by quarter 73 116EPS Guidance 5, 12, 49, 50, 51, 56, 57, 64, 66, 74 113, 114, 115, 116, 117

Merchant Gross Margin 76, 77, 85 Income from Operations / Net Income 118, 119, 120, 121Merchant Below Gross Margin 76, 77, 85 118, 119, 120, 121Merchant Projected Gross Margin 85, 86 118, 119, 120, 121Merchant Projected Below Gross Margin 85, 86 118, 119, 120, 121

BGE Gross Margin 104, 105 Income from Operations / Net Income 122BGE EBIT 104 122BGE EBITDA 107, 108 122BGE Below Gross Margin 104 122BGE Projected Gross Margin and Below Gross Margin 104, 105, 107, 108 122

Debt to Total Capital 62 Debt Divided by Total Capitalization 123Projected Debt to Total Capital 62 123

Net Cash Flow before Debt Issuances (Payments) 78, 87 Operating, Investing and Financing Cash Flow 124Free Cash Flow 78, 87 124Projected Cash Flow 61, 87 124

113

113

Adjusted EPS 2007 and 2006

RECONCILIATION:Merchant Regulated Regulated Other

($ per share) Energy Electric Gas BGE Nonreg. Total

A B C D = (B+C) E F =(A+D+E)

2007 ACTUAL RESULTS:

Reported GAAP EPS 3.72$ 0.53$ 0.16$ 0.69$ 0.09$ 4.50$

Income from Discontinued Operations (0.01) - - - - (0.01) GAAP MEASURES

3.73 0.53 0.16 0.69 0.09 4.51

Special Items, Non-qualifying Hedges, and Synfuel Results Included in Operations:

Non-qualifying Hedges 0.01 - - - - 0.01

Synthetic fuel facility results (0.02) - - - - (0.02)

Maryland Corporate Tax Rate 0.05 (0.05) - (0.05) -

Impairment losses and Other Costs (0.07) - - - (0.07)

Workforce Reduction Costs (0.01) - - - - (0.01)

Total Special Items, Non-qualifying Hedges, and Synfuel Results (0.04) (0.05) - (0.05) - (0.09)

Adjusted EPS 3.77$ 0.58$ 0.16$ 0.74$ 0.09$ 4.60$ NON-GAAP MEASURE



Income from Discontinued Operations 1.03 - - - 0.01 1.04 GAAP MEASURES

EPS Before Discontinued Operations 3.20 0.66 0.20 0.86 0.06 4.12


Gain on sale of gas-fired plants (excluding High Desert) 0.26 - - - - 0.26

Non-qualifying hedges 0.21 - - - - 0.21

Synthetic fuel facility results 0.16 - - - - 0.16

Workforce reduction costs (0.09) - - - - (0.09)

Merger-related costs (0.02) (0.01) - (0.01) - (0.03)

Total Special Items, Non-qualifying Hedges, and Synfuel Results 0.52 (0.01) - (0.01) - 0.51


EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact ofspecial items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

EPS Before Discontinued Operations

We exclude special items and certain economic, non-qualifying fuel adjustment clause and gas transportation and storage hedges because we believe that it is appropriate for investors to consider results excluding these items, in addition to our results in accordance with GAAP. We have also adjusted earnings to exclude synfuel results due to the potential volatility and phase-out of the tax credits. We believe such a measure provides a picture of our results that is comparable among periods since it excludes the impact of items, which may recur occasionally, but tend to be irregular as to timing and magnitude, thereby distorting comparisons between periods. However, investors should note that this non-GAAP measure involves judgment by management (in particular, judgments as to what is or is not classified as a special item). We also use this measure to evaluate performance and for compensation purposes.

114

114

Adjusted EPS YTD 2005

RECONCILIATION:

($ per share) Total


Reported GAAP EPS 3.47$

Income from Discontinued Operations 0.53 GAAP MEASURES

Cumulative Effects of Changes in Accounting Principles (0.04)

2.98

Special Items and Non-qualifying Hedges Included in Operations:

Non-qualifying Hedges (0.14)

Synthetic fuel facility results 0.33

Merger-related costs (0.09)

Workforce reduction costs (0.01)

Total Special Items, Non-qualifying Hedges, and Synfuel Results 0.09

Adjusted EPS 2.89$ NON-GAAP MEASURE

EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact of special items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

EPS Before Discontinued Operations and Cumulative Effects of Changes in Accounting Principles


115

115

Adjusted EPS 4Q07 and 4Q06

RECONCILIATION:Merchant Regulated Regulated Other

($ per share) Energy Electric Gas BGE Nonreg. Total

A B C D = (B+C) E F =(A+D+E)

4Q07 ACTUAL RESULTS:Reported GAAP EPS 1.26$ 0.06$ 0.06$ 0.12$ 0.04$ 1.42$ GAAP MEASURES


Synthetic fuel facility results (0.11) - - - - (0.11)


Maryland Corporate Tax Rate 0.05 (0.05) - (0.05) - -

Total Special Items and Non-qualifying Hedges (0.01) (0.05) - (0.05) - (0.06)


4Q06 ACTUAL RESULTS:Reported GAAP EPS 2.01$ 0.13$ 0.06$ 0.19$ 0.02$ 2.22$

Income from Discontinued Operations 0.76 - - - - 0.76 GAAP MEASURES

1.25 0.13 0.06 0.19 0.02 1.46


Gain on sale of gas-fired plants (excluding High Desert) 0.26 - - - - 0.26



Merger related transaction costs 0.01 0.01 - 0.01 - 0.02

Workforce reduction costs (0.01) - - - - (0.01)

Total Special Items and Non-qualifying Hedges 0.37 0.01 - 0.01 - 0.38





116

116

Quarterly Adjusted EPS – 2006 and 2007

RECONCILIATION:2006 2007

($ per share) Q1 06 Q2 06 Q3 06 Q4 06 Total Q1 07 Q2 07 Q3 07 Q4 07 Total

ACTUAL RESULTS:

Reported GAAP EPS 0.63$ 0.52$ 1.79$ 2.22$ 5.16$ 1.07$ 0.64$ 1.38$ 1.42$ 4.50$

Income from Discontinued Operations - High Desert 0.07 0.11 0.10 0.76 1.03 (0.01) - 0.01 - (0.01)

Income from Discontinued Operations - Others - - - - 0.01 - - - - -

0.56 0.41 1.69 1.46 4.12 1.08 0.64 1.37 1.42 4.51


Gain on sale of gas-fired plants (excluding High Desert) - - - 0.26 0.26 - - - - -

Synthetic fuel facility results 0.02 (0.01) 0.11 0.04 0.16 0.10 0.07 (0.09) (0.11) (0.02)

Non-qualifying hedges (0.06) - 0.20 0.07 0.21 (0.05) 0.01 0.01 0.05 0.01

Impairment losses and Other Costs - - - - - - (0.07) - - (0.07)

Merger related transaction costs (0.01) (0.03) (0.01) 0.02 (0.03) - - - -

Workforce reduction costs - - (0.07) (0.01) (0.09) - (0.01) - - (0.01)

Total Special Items and Non-qualifying Hedges (0.05) (0.04) 0.23 0.38 0.51 0.05 - (0.08) (0.06) (0.09)

Adjusted EPS 0.61$ 0.45$ 1.46$ 1.08$ 3.61$ 1.03$ 0.64$ 1.45$ 1.48$ 4.60$


EPS Before Discontinued Operations and Cumulative Effects of Changes in Accounting Principles


117

117

Adjusted EPS – 1Q07

RECONCILIATION:Regulated Regulated Other

($ per share) Merchant Electric Gas BGE Nonreg. Total

A B C D = (B+C) E F =(A+D+E)

1Q07 ACTUAL RESULTS:


Loss from Discontinued Operations (0.01) - - - - (0.01) GAAP MEASURES

0.67 0.18 0.18 0.36 0.05 1.08


Non-qualifying hedges (0.05) - - - - (0.05)


Total Special Items, Non-qualifying Hedges, and Synfuel Results 0.05 - - - - 0.05


EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items, non-qualifying hedges, and synfuel results to GAAP earnings per share because we do not predict the future impact of special items such as the cumulative effect of changes in accounting principles, the disposition of assets, economic, nonqualifying hedges or synfuel results.



118

118

2007 Merchant Gross Margin and Below Gross Margin

RECONCILIATION:GAAP Adjustments Merchant

GAAP Fuel & Purchased In Arriving Gross MarginMerchant Revenue & Expense Categories Revenues Energy Expenses Difference At Gross Margin Notes (Non-GAAP)

($ millions)Mid-Atlantic Fleet 3,462.2$ 2,214.4$ 1,247.8$ (214)$ a, b, c 1,035$ Plants with PPAs 657.3 78.5 578.8 25 a 604 Wholesale Competitive Supply 5,469.4 4,618.1 851.3 275 a, d, e, g, h 1,126 NewEnergy 9,086.3 8,590.8 495.5 (75) d, h, o 420 QFs / Other 69.3 - 69.3 (18) e, f, h 51

Total Merchant 18,744.5$ 15,501.8$ 3,242.7$ (7)$ 3,236$

Adjustments Merchant Below Arriving At Merchant Gross Margin

Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 3,242.7$ 3,236$ Operations and maintenance expenses (1,791.3) 111 i, j, k, o (1,680) Impairment loss (20.2) 20 n - Workforce reduction costs (2.3) 2 n - Depreciation, depletion, and amortization (269.9) (13) j, k (283) Taxes other than income taxes (110.2) 110 l - Accretion of asset retirement obligations (68.3) 68 l -

Income From Operations 980.5 1,273 Gain on sale of equity of CEP LLC 63.3 (63) g - Other income / (expense) 55.0 (145) b, k, l, m, o (92)

EBIT N/A 1,181 Fixed charges (86.8) 27 k, m (60)

Income Before Income Taxes 1,012.0 1,121 Income tax expense (332.8) (99) k, n (433)

Income from Continuing Operations 679.2 688 Income from discontinued operations (0.9) 1 p -

Net Income 678.3$ 688$

Details of Adjustments Made in Arriving at Merchant Gross Margin:a Adjustment to remove ($206 million) gain from Mid-Atlantic Fleet and $25 million loss from Plants with PPA's of estimated gross margin created through active portfolio

management more appropriately categorized as a competitive supply activity.b Adjustment to remove ($19 million) of decommissioning revenues from non-GAAP gross margin measure and included in Other Income. The offsetting decommissioning

expense was recorded in accretion of asset retirement obligations.c Adjustment to remove $12 million of other indirect costs from non-GAAP gross margin as they are more appropriately categorized as operating expenses.d Adjustment to remove $12 million loss in Wholesale Competitive Supply and ($15 million) gain in NewEnergy related to economic, non-qualifying hedges of gas transport and storage contracts.e Adjustment to remove synfuel losses from Wholesale Competitive Supply gross margin of $27 million and Other gross margin of $26 million.f Adjustment to reflect ($40 million) of direct costs in Other for purposes of non-GAAP gross margin measure.g Adjustment to move $63 million gain on sale of stock by CEP to gross margin to reflect management's view of this activity as part of operations.h Reclassification of certain gross margin amounts in Wholesale Competitive Supply ($9 million) and Other ($4 million) that is more appropriately classified as Retail

since it relates to our Cornerstone acquisition

Details of Adjustments Made in Arriving at Merchant Below Gross Margin:i Adjustment detailed in "c" and "f" above are offset by adjustments made to O&M costs. j Adjustment to reclassify certain allocated costs totaling $33 million from O&M to Depreciation and Amortization.k Adjustment to remove Synfuel results, which are not included in determining Merchant Below Gross Margin - $15 million in O&M, $20 million in D&A, $8 million in Fixed Charges, $2 million from other income, and ($91 million) from income tax expense.l Adjustment to reflect management's view of these items as Other Income / Expense.m Adjustment to move Interest Income of $19 million recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).n Adjustment to remove Special Items and taxes ($8 million) which are not included in determining Merchant Below Gross Margin.o Reclassification to gross margin of $73 million in costs associated with aggregator fees ($35 million recorded in O&M) and gross receipts tax expense ($38 million) recorded in other expense. These are pass through charges for which we record revenues from customer billings.p Discontinued operations is considered a special item by management.

PROJECTED GROSS MARGIN AND RESULTS BELOW GROSS MARGIN:Constellation Energy is unable to reconcile its projected gross margin or results below gross margin to GAAP because we do not predict the future impact of reconciling items or special items such as the cumulative effect of changes in accounting principles and the disposition of assets.

Year Ended December 31, 2007

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Mid-Atlantic Fleet, Plants with PPAs, Wholesale Competitive Supply, NewEnergy, and QFs/Other). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

119

119

2006 Merchant Gross Margin and Below Gross Margin



($ millions)Mid-Atlantic Fleet 2,813.5$ 1,727.6$ 1,085.9$ (300)$ a, b, c 786$ Plants with PPAs 650.5 67.9 582.6 (8) a 574 Wholesale Competitive Supply 5,612.7 4,890.6 722.1 319 a , d, e, l 1,040 NewEnergy 8,014.7 7,570.2 444.5 (105) d, p 340 QFs / Other 74.8 - 74.8 (22) e, f 53

Total Merchant 17,166.2$ 14,256.3$ 2,909.9$ (116)$ 2,793$


Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 2,909.9$ 2,793$ Operations and maintenance expenses (1,549.4) 84 g, h, i, p (1,465) Merger related transaction costs (13.1) 13 j - Workforce reduction costs (28.2) 28 j - Depreciation and amortization (258.7) 2 h, i (257) Taxes other than income taxes (120.0) 120 k - Accretion of asset retirement obligations (67.6) 68 k - Gain on sale of gas-fired plants (excluding High Desert) 73.8 (74) j -

Income From Operations 946.7 1,071 Gain on initial Public Offering of CEP LLC 28.7 (29) l - Other income / (expense) 46.7 (146) b, i, j, l, p (99)

EBIT N/A 972 Fixed charges (191.7) 23 i, m (169)

Income Before Income Taxes 830.4 803 Income tax expense (250.2) (68) i, j, n, o (318)

Income from Continuing Operations 580.2 485 Income from discontinued operations 186.9 (187) j -


Details of Adjustments Made in Arriving at Merchant Gross Margin:a Adjustment to remove ($295 million) gain from Mid-Atlantic Fleet and ($8 million) gain from Plants with PPA's of estimated gross margin created through active portfolio


expense was recorded in accretion of asset retirement obligations.c Adjustment to remove $14 million of other indirect costs from non-GAAP gross margin as they are more appropriately categorized as operating expenses.d Adjustment to remove ($30 million) gain in Wholesale Competitive Supply and ($34 million) gain in NewEnergy related to economic, non-qualifying hedges of gas transport contracts.e Adjustment to remove synfuel losses from Wholesale Competitive Supply gross margin of $17 million and Other gross margin of $20 million.f Adjustment to reflect ($42 million) of direct costs in Other for purposes of non-GAAP gross margin measure.

Details of Adjustments Made in Arriving at Merchant Below Gross Margin:g Adjustment detailed in "c" and "f" above are offset by adjustments made to O&M costs. h Adjustment to reclassify certain allocated costs totaling $22 million from O&M to Depreciation and Amortization.i Adjustment to remove Synfuel results, which are not included in determining Merchant Below Gross Margin - $9 million in O&M, $24 million in D&A, $6 million in Fixed Charges, and ($104 million) from income tax expense.j Adjustment to remove Special Items and related taxes - $7 million, which are not included in determining Merchant Below Gross Margin.k Adjustment to reflect management's view of these items as Other Income / Expense.l Adjustment to move $29 million gain on initial public offering of CEP to gross margin to reflect management's view of this activity as part of operationsm Adjustment to move Interest Income of $17 million recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).n Adjustment to remove tax expense of $25 million related to gains on economic, non-qualifying hedges of gas transportation and storage contracts.o Adjustment to reclassify $4 million of tax expense to other income / (expense) associated with income from decommissioning included in other income / (expense).p Reclassification to gross margin of $71 million in costs associated with aggregator fees ($26 million recorded in O&M) and gross receipts tax expense ($45 million) recorded in other expense. These are pass through charges for which we record revenues from customer billings.




120

120

Q407 Merchant Gross Margin and Below Gross Margin



($ millions)Mid-Atlantic Fleet 865.4$ 544.7$ 320.7$ (91)$ a, b, c 230$ Plants with PPAs 139.7 20.1 119.6 13 a 133 Wholesale Competitive Supply 1,194.9 899.1 295.8 78 a, d, e, g, h 374 NewEnergy 2,415.1 2,229.9 185.2 (16) d, h, o 170 QFs / Other 15.8 - 15.8 (6) e, f 9

Total Merchant 4,630.9$ 3,693.8$ 937.1$ (22)$ 916$


Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 937.1$ 916$ Operations and maintenance expenses (453.9) 27 i, j, k, o (426) Depreciation, depletion, and amortization (72.3) (6) j, k (78) Taxes other than income taxes (25.2) 25 l - Accretion of asset retirement obligations (16.4) 16 l -

Income From Operations 369.3 412 Gain on initial Public Offering of CEP LLC 11.2 (11) g - Other income / (expense) 20.3 (37) b, k, l, m, o (17)

EBIT N/A 395 Fixed charges (25.2) 8 k, m (18)

Income Before Income Taxes 375.6 377 Income tax expense (146.6) 2 k, n (146)




expense was recorded in accretion of asset retirement obligations.c Adjustment to remove $4 million of other indirect costs from non-GAAP gross margin as they are more appropriately categorized as operating expenses.d Adjustment to remove $4 million gain in Wholesale Competitive Supply and $9 million gain in NewEnergy related to economic, non-qualifying hedges of gas transport and storage contracts.e Adjustment to remove synfuel losses from Wholesale Competitive Supply gross margin of $6 million and Other gross margin of $5 million.f Adjustment to reflect ($11 million) of direct costs in Other for purposes of non-GAAP gross margin measure.g Adjustment to move $11 million gain on sale of stock by CEP to gross margin to reflect management's view of this activity as part of operations.h Reclassification of certain gross margin amounts in Wholesale Competitive Supply ($13 million) that is more appropriately classified as Retail

since it relates to our Cornerstone acquisition

Details of Adjustments Made in Arriving at Merchant Below Gross Margin:i Adjustment detailed in "c" and "f" above are offset by adjustments made to O&M costs. j Adjustment to reclassify certain allocated costs totaling $9 million from O&M to Depreciation and Amortization.k Adjustment to remove Synfuel results, which are not included in determining Merchant Below Gross Margin - $3 million in O&M, $3 million in D&A, $2 million in Fixed Charges, $1 million from other income, and ($3 million) from income tax expense.l Adjustment to reflect management's view of these items as Other Income / Expense.m Adjustment to move Interest Income of $6 million recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).n Adjustment to remove Special Items and taxes ($5 million) which are not included in determining Merchant Below Gross Margin.o Reclassification to gross margin of $19 million in costs associated with aggregator fees ($9 million recorded in O&M) and gross receipts tax expense ($8 million) recorded in other expense. These are pass through charges for which we record revenues from customer billings.


Quarter Ended December 31, 2007


121

121

Q406 Merchant Gross Margin and Below Gross Margin



($ millions)Mid-Atlantic Fleet 694$ 357$ 337$ (102)$ a, b, c 235$ Plants with PPAs 133 21 112 13 a 124 Wholesale Competitive Supply 1,276 1,117 158 114 a , d, e, l 272 NewEnergy 2,050 1,903 147 (28) d, p 119 QFs / Other 14 - 14 (3) e, f 11

Total Merchant 4,166$ 3,398$ 768$ (6)$ 761$


Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 768$ 761$ Operations and maintenance expenses (403) 22 g, h, i (380) Merger related transaction costs (4) 4 j - Workforce reduction costs (4) 4 j - Depreciation and amortization (59) (1) h, i (60) Taxes other than income taxes (29) 30 k - Accretion of asset retirement obligations (17) 17 k - Gain on sale of gas-fired plants (excluding High Desert) 74 (74) j -

Income From Operations 324 321 Gain on initial Public Offering of CEP LLC 29 (29) l - Other income / (expense) 18 (43) b, i, j, l (25)

EBIT N/A 296 Fixed charges (39) 7 i, m (31)

Income Before Income Taxes 332 265 Income tax expense (102) (3) i, j, n, o (104)

Income from Continuing Operations 230 161 Income from discontinued operations 137 (137) j -

Net Income 367$ 161$



expense was recorded in accretion of asset retirement obligations.c Adjustment to remove $4 million of other indirect costs from non-GAAP gross margin as they are more appropriately categorized as operating expenses.d Adjustment to remove ($11 million) gain in Wholesale Competitive Supply and ($11 million) gain in NewEnergy related to economic, non-qualifying hedges of gas transport contracts.e Adjustment to remove synfuel losses from Wholesale Competitive Supply gross margin of $7 million and Other gross margin of $5 million.f Adjustment to reflect ($8 million) of direct costs in Other for purposes of non-GAAP gross margin measure.

Details of Adjustments Made in Arriving at Merchant Below Gross Margin:g Adjustment detailed in "c" and "f" above are offset by adjustments made to O&M costs. h Adjustment to reclassify certain allocated costs totaling $6 million from O&M to Depreciation and Amortization.i Adjustment to remove Synfuel results, which are not included in determining Merchant Below Gross Margin - $4 million in O&M, $5 million in D&A, $2 million in Fixed Charges, and ($30 million) from income tax expense.j Adjustment to remove Special Items and related taxes - $14 million, which are not included in determining Merchant Below Gross Margin.k Adjustment to reflect management's view of these items as Other Income / Expense.l Adjustment to move $29 million gain on initial public offering of CEP to gross margin to reflect management's view of this activity as part of operationsm Adjustment to move Interest Income of $5 million recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).n Adjustment to remove tax expense of $9 million related to gains on economic, non-qualifying hedges of gas transportation and storage contracts.o Adjustment to reclassify $5 million of tax expense to other income / (expense) associated with income from decommissioning included in other income / (expense).p Reclassification to gross margin of $17 million in costs associated with aggregator fees ($8 million recorded in O&M) and gross receipts tax expense ($9 million) recorded in other expense. These are pass through charges for which we record revenues from customer billings.


Quarter Ended December 31, 2006


122

122

BGE Gross Margin, Below Gross Margin, EBIT, and EBITDA

RECONCILIATION:

Utility:GAAP Electric

Segment ResultsGAAP Gas Segment

ResultsTotal Utility

Results Adjustments Notes (Non-GAAP)Revenue

Total Electric Revenues 2,455.7$ -$ 2,455.7$ Total Gas Revenues - 962.8 962.8 Total Regulated Revenues 2,455.7 962.8 3,418.5

Operating ExpensesPurchased Power Costs

Electricity Purchased for Resale (1,500.4) - (1,500.4) Gas Purchased for Resale - (639.8) (639.8) Total Purchased Power Costs (1,500.4) (639.8) (2,140.2)

Gross Margin 955.3 323.0 1,278.3 1,278$ Operations and maintenance expenses (376.1) (157.5) (533.6) 12 a (522) Depreciation and amortization (187.5) (46.8) (234.3) (12) a (246) Taxes other than income taxes (140.3) (36.1) (176.4) 176 c -

Income From Operations 251.4 82.6 334.0 510 Other income 18.7 (0.1) 18.6 (192) b, c, d (173)

EBIT N/A N/A N/A 337 Interest expense (97.7) (27.6) (125.3) 24 d (101)

Income Before Income Taxes 172.4 54.9 227.3 236 Income tax expense (64.6) (22.8) (87.4) (88)

Net Income 107.8 32.1 139.9 148 Preference Stock Dividends (9.9) (3.3) (13.2) (13) Earnings Applicable to Common Stock 97.9$ 28.8$ 126.7$ 135$

Details of Adjustments:a Adjustment to reclassify certain allocated costs totaling $12 million from O&M to Depreciation and Amortization.b Adjustment to remove the Maryland Corporate Tax Rate expenses that management views as a special item.c Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. d Adjustment to move Interest Income recorded in Other Income to Fixed Charges (to show a fixed charge amount net of interest income).

Calculation of EBITDA:Gross margin 955$ 323$ Operations and maintenance expenses (376) (158) Taxes other than income taxes (140) (36) Other income 19 (0) Non-GAAP adjustments made above and allocation of corporate items (16) (1) EBITDA 442$ 128$



We utilize these non-GAAP financial measures to highlight the relationship between the costs of and prices for energy and to highlight the primary driver of earnings at our Regulated Utility. We believe these non-GAAP measures help investors to better understand the changes in the level of our Utility operating results from period to period.

123

123

Net Debt to Total Capital

RECONCILIATION:

Total long-term debt (gross of current portion) 4,788.2$ 4,788.2$ 4,849.3$ 4,849.3$ 3,874.4$ 3,874.4$

Fair value decrease (increase) in fixed to floating rate swap included in long-term debt (11.8) 7.1 -

6.20% deferrable interest subordinated debentures due

October 15, 2043 to BGE wholly owned BGE Capital

Trust II relating to trust originated preferred securities 257.7 257.7 257.7 257.7 250.0 250.0 50% Equity credit to trust preferred securities - (125.0) - (125.0) - (125.0)

Adjustment to include High Desert Lease on Balance Sheet at December 31, 2001 - - - - - 221.0 Short-term borrowings 14.0 14.0 - - 975.0 975.0 Unamortized discount and premium (4.8) - (5.9) - (5.2) - Subtotal 5,055.1 4,923.1 5,101.1 4,989.1 5,094.2 5,195.4 LESS: Cash - 1,095.9 - 2,289.1 - 72.4 Total Net Debt 5,055.1 3,827.2 5,101.1 2,700.0 5,094.2 5,123.0 Rate stabilzation securitization bonds of BGE (623.2) - - Net Debt for Debt to Capital Ratio 5,055.1 3,204.0 36.1% 5,101.1 2,700.0 35.0% 5,094.2 5,123.0 54.6%

BGE Preference Stock Not Subject To Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 190.0 Minority Interests - 19.2 - 94.5 - 101.8 Common shareholders' equity 5,340.2 5,340.2 4,611.7 4,611.7 3,843.6 3,843.6

Subtotal 5,530.2 5,549.4 4,801.7 4,896.2 4,033.6 4,135.4 50% Equity credit to trust preferred securities - 125.0 - 125.0 - 125.0

Total Equity 5,530.2 5,674.4 63.9% 4,801.7 5,021.2 65.0% 4,033.6 4,260.4 45.4%

Total Capitalization 10,585.3 9,501.6 9,902.8 7,721.2 9,127.8 9,383.4

Rate stabilzation securitization bonds of BGE (623.2) - - Total capitalization for Debt to Capital Ratio 10,585.3$ 8,878.4$ 100.0% 9,902.8$ 7,721.2$ 100.0% 9,127.8$ 9,383.4$ 100.0%

Exclude commodity hedge AOCI Balance from common shareholders' equity and rate stabilization bonds 940 1,379 (30.0) Counterparty cash collateral held reflected as a reduction of cash balance and rate stabilzation bonds (270) (253) - Adjusted Net Debt to Total Capital 34.5% 31.6% 54.8%

PROJECTED LEVERAGE RATIOS:Constellation Energy is unable to provide a reconciliation of this measure for future periods because it does not prepare a forecasted balance sheet on a GAAP basis.

December 31, 2001

GAAP Balances Non-GAAP Ratio

December 31, 2007


December 31, 2006


Debt to Total Capital is a non-GAAP ratio that excludes unamortized discounts and premiums, reduces debt by our cash balance, and includes minority interests in equity. In addition, we reflect a 50 percent equity credit for our trust preferred securities and remove the non-economic impact commodity hedges and cash collateral held, similar to the evaluation performed by major credit rating agencies. Management believes this non-GAAP measures provide investors useful information on our leverage because it is consistent with the evaluation performed by rating agencies, takes into account minority equity interests in our consolidated affiliates and cash available to reduce debt, and facilitates comparability between periods.

124

124

Cash Flows – 2007, 2006, 2005The following is a reconciliation of the non-GAAP financial measures of Net Cash Flow before Debt Issuances/Payments and Free Cash Flow. We utilize these non-GAAP measures because we believe they are helpful in understanding our ability to reduce debt by existing cash.

RECONCILIATION:

YTD DECEMBER ACTUAL RESULTS:Net cash provided by operating activities (GAAP measure) 928 525 627 Adjustment to reflect operating use of cash in connection with contract acquisitions

as a financing use - - 72 Adjustment for derivative contracts presented as financing activities under SFAS 149 (32) (3) 73 Adjusted Net Cash Provided by Operating Activities 896$ 522$ 772$ NON-GAAP MEASURE

Net cash used in investing activities (GAAP measure) (2,287) 560 (1,174) Adjustment to reflect investing use of cash in connection with contract acquisitions

as a financing use - - 419 Non-GAAP adjustment for Cogenex debt acquired - - (19) Adjusted Net Cash Used in Investing Activities (2,287) 560 (774) NON-GAAP MEASURE

Net Cash Used in Financing Activities (Excl. Debt-Related Sources & Uses) *Common stock dividends paid (306) (264) (229) Proceeds from issuance of common stock 65 84 97 Reacquisition of common stock (410) - - Net proceeds from acquired contracts 848 221 537 Other financing activities, excluding SFAS 149 activities included in operating 35 (3) 26 Adjusted Net Cash Used in Financing Activities 232 38 431

Net Cash Flow before Debt Issuances/(Payments) (1,159) 1,120$ 429$ NON-GAAP MEASURE

Less: Proceeds from issuance of common stock (65) (84) (97) Add: Reacquisition of common stock 410 - - Add: Common stock dividends paid 306 264 229

Free Cash Flow (509)$ 1,300$ 561$ NON-GAAP MEASURE

PROJECTED CASH FLOWS:Constellation Energy is unable to provide a reconciliation of these measures for Projected 2008 because it does not prepare a forecasted statement of cash flows on a GAAP basis.

* Total GAAP Cash Used in Financing Activities (incl. debt-related sources & uses) was $166 million YTD December 07, $391 million YTD December 2006, and $654 million YTD December 05.

($ millions)2007 2006 2005

Economy & Finance

constellation energy Q4 2007 Earnings Presentation 2007 Fourth Quarter