constellation energy Q4 2006 Earnings Presentation 2006 Fourth Quarter

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Constellation Energy2007 Analyst Presentation

January 31, 2007

Kevin Hadlock:

We’re going to go ahead and get started.

Good morning everyone. I am Kevin Hadlock, Vice President, Investor Relations for Constellation Energy. Welcome to our 2007 analyst presentation and fourth quarter earnings call. I’m glad that so many of you could join us here in New York today and on the phone.

Moving to slide 2…

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Forward-looking Statements DisclaimerCertain 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 projected results. 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; the inability of BGE to recover all its costs associated with providing electric residential 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 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. Given these 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 constellation.com under Investor Relations.


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Use of Non-GAAP Financial MeasuresConstellation Energy presents adjusted earnings per share (adjusted EPS) in addition to its reported earnings per share in accordance with generally accepted accounting principles (reported GAAP EPS). Adjusted EPS is a non-GAAP financial measure that 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 such measures provide 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 these non-GAAP measures involve judgments by management (in particular, judgments as to what is classified as a special item or an economic, non-qualifying hedge to be excluded from adjusted earnings). These non-GAAP measures are also used to evaluate management's performance and for compensation purposes. Constellation Energy also provides its earnings guidance in terms of adjusted EPS. Constellation Energy is unable to reconcile its 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 such information is 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. 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.

We will use Non-GAAP financial measures in this presentation to help you understand our operating performance.

We have attached an Appendix to the charts on the website reconciling Non-GAAP measures to GAAP measures.

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

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Agenda

9:25 – 9:50

8:50 – 9:25

8:25 – 8:50

8:05 – 8:25

TimeSpeakerTopic

AllQuestions & Answers

Follin SmithFinancials

Tom BrooksCompetitive Business Overview

Mayo ShattuckOverview

Thank you, Kevin. Good morning everybody, and I welcome all of you who have joined us here in New York and those who are participating via telephone and webcast. We’re glad that so many of you have joined us this morning.

So, here is our agenda for this morning. First, I’m going to provide an industry and company overview. After that, Tom Brooks, who was recently named president of our integrated merchant organization, will provide an overview of our competitive businesses.

And then, Follin Smith, our CFO and Chief Administrative Officer, will cover our financials.

After Follin, we will have plenty of time for questions.

Let’s begin on slide 5…

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2006 Highlights• Generated adjusted EPS growth of 24.9%

– Adjusted EPS results of $3.61 exceeded guidance of $3.30 to $3.45 per share

• Delivered total shareholder return of 22.7% in 2006

• Reinforced foundation to support continuation of successful growth– Exercised capital discipline through

monetization of gas-fired generation plants– Applying proceeds to further strengthen

balance sheet– Demonstrated industry leadership position

IPO of Constellation Energy PartnersCultivated option for nuclear renaissance through UniStar

2006 Adjusted EPS Growth Rates

24.9%

16.5%14.8%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

CEG S&P Elec Index S&P 500

• Continued to deliver superior EPS growth and to drive strong total shareholder return• Poised to continue success in 2007 and beyond

See Appendix

This management team is sharply focused on delivering results and, in 2006, we had another outstanding year. We grew earnings by almost 25% and generated adjusted earnings of $3.61 per share. This performance exceeded management’s 2006 guidance given at the beginning of the year of $3.00 to $3.30 and our more recent adjusted guidance range of $3.30 to $3.45 per share. Our earnings growth rate outpaced the S&P Electric Utility Index and the S&P 500 by more than 8 percentage points. I am very proud of this management team and all of our employees for their accomplishments.

Our success in delivering such strong earnings also translated into significant total return for shareholders. Considering both stock price appreciation and dividends, we drove total shareholder return of nearly 23% in 2006, following the 35% total shareholder return realized in 2005.

During 2006, we continued to reinforce the foundation to support future growth of our business. The successful sale of our gas-fired generation plants demonstrated our capital discipline to sell assets when the market value exceeds our internal valuation. Proceeds from the plant sale have enabled us to achieve our balance sheet targets, and we will redeploy the balance to attractive investment opportunities in generation, competitive supply, and transmission and distribution. Finally, the creation of Constellation Energy Partners and the evaluation of new nuclear possibilities are just two examples of how we are demonstrating our industry leadership position.

In summary, we continued to deliver superior earnings growth and to drive strong total shareholder return for our investors in 2006. As you will see throughout this presentation, we are poised to continue our success in 2007 and beyond.

Moving to page 6…

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Constellation Business Activities

• Unique combination of businesses creates sustainable competitive advantage• Value of each business enhanced through integration• Outlook for each business very strong

Physical Supply Assets

Risk Management& Investing

Regulated Transmission & Distribution

Load Serving

So today, I want to talk about our businesses in a way that may be a little different than how we have discussed them in the past. I will focus more on the types of business activities that occur in the company, rather than the organizational sticks and boxes some of you might be accustomed to seeing.

On a high level, this chart shows how we think about the businesses we have created. Constellation is built on a solid foundation of physical supply assets.

We also have a regulated transmission and distribution business, Baltimore Gas & Electric. These two businesses represent what most of you think of as an integrated utility.

In load serving, we act as an intermediary between suppliers and consumers of energy. Effectively, we are selling insurance products to producers of energy—who want to manage their risk as they sell their output—and to consumers of energy—who want to manage their price risk. We have built this franchise into the industry-leading platform that has a substantial lead on our competitors.

While each of these businesses are independently valuable, we are leveraging their value by integrating them into a single platform. Scale, extensive knowledge of physical logistics, focus on customer needs, and a disciplined risk management approach give us a strong competitive edge.

This year, we are in a position to leverage this scale and market expertise by realigning our merchant platform, which will drive our long-term growth and profitability. The realignment of all our merchant businesses allows us to leverage our world-class capabilities in risk management and portfolio management across our industry-leading platform. Tom Brooks will talk more about this in his presentation.

So, turning to slide 7…

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• Growing need for significant infrastructure investment in many areas of energy sector– Electricity demand outpacing supply additions, resulting in declining reserve

margins– Transmission infrastructure investment needed for grid reliability– Growing demand for natural gas

• Evolving debate on energy policy will drive additional investment– Environmental compliance causing significant industry investment– Carbon standards will increase focus on alternative energy investment

• Stabilizing regulatory environment supportive of new utility investment– Potential for higher efficiency through advanced metering technology and demand

response initiatives

Outlook for Physical Supply Asset Investment

• Industry fundamentals are attractive for physical supply asset investment driven by growing macro supply and demand imbalances, energy policy initiatives and a stabilizing regulatory environment that will drive investment opportunities

As we look at the energy sector, industry fundamentals are attractive for increasing investment in physical supply assets. There is a clear and growing need for significant infrastructure investment throughout the sector. Electricity demand is outpacing supply additions in most regions around the country. In certain areas of PJM, where we have a significant physical asset presence, reserve margins are expected to decline and to signal the need for new investment. Growing demand for natural gas will also create a need for additional investment in supply assets.

The evolving debate on energy policy will also drive additional investment. Coal plants are requiring billions of dollars of investment in emissions abatement equipment over the next decade to meet environmental compliance standards. Carbon restrictions are on the horizon and will increase the industry’s focus on alternative energy investment.

Following a year of debate around rising commodity prices, expiring rate caps and election-year politicking, the regulatory environment is stabilizing and becoming more supportive of new investment. The desire for enhanced load management will drive the need for advanced metering and demand response initiatives. These areas will provide opportunities for transmission and distribution utilities to invest capital and earn a regulated return.

So, how do we take advantage of these trends? Turning to slide 8…

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Impact of Industry Outlook on Constellation

• Constellation owns high-quality generation assets located in high-value competitive markets– Scarcity pricing will benefit incumbent generators– Potential for future generation development at existing Constellation

sites

• Strong Merchant platform sets the stage for further growth– Expect to leverage successful growth in gas business– Constellation Energy Partners provides low-cost financing partner

• Industry fundamentals favor Constellation’s strategic position

• Significant opportunities exist for future investment

Because we own high-quality generation assets in high value markets, Constellation should benefit from the need for more physical supply asset investment. Deregulation should cause scarcity pricing signals to be sent to the market and encourage the build of new generation capacity when necessary. As this happens, incumbent generators will be advantaged. In the near term, Constellation will benefit from capacity market reform in PJM. When new capacity is required, Constellation will be well-positioned for future generation development at existing sites in constrained zones.

Finally, our strong Merchant platform has set the stage for further investment and growth. We expect to leverage our successful growth in the gas business. The completed IPO of Constellation Energy Partners provides a low-cost funding partner to further our growth in this business.


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Imperative to Address Global Climate Change

• Near-term plan to address global climate change is necessary– Effective solution must be market-oriented, economy-wide, equitable

among industries and national, then international– Competition is crucial to addressing global climate change

• U.S. CO2 emissions cap-and-trade program likely near term– Potential carbon market could create additional trading opportunities

• Evolving carbon policy will favor Constellation’s low-emitting generation fleet– Approximately 60% of Constellation’s generation output comes from

zero emission sources of nuclear and hydro• Constellation’s low-emitting fleet combined with experience and knowledge of wholesale

markets will be highly leverageable in an emissions trading market place

Constellation believes it is imperative to slow, then stop and eventually reverse the growth of greenhouse gases going into the atmosphere and is working with state and federal policymakers to that end. The effective solution set must be market oriented, economy-wide, equitable among industries and – very importantly – national, and then international in scope. We also believe that the benefits of efficiency and innovation driven by competition are crucial to addressing global climate change.

A cap-and-trade program in the power sector with lessons learned from the European Union experience should and likely will become a feature of national climate policy in the near term. The details of such a program are impossible to predict today and may take years to enact into law, but it is worth noting that Constellation is well positioned for the development of this market. Our commodities trading experience and position in and knowledge of the wholesale markets will be highly leveragable in an emissions trading market place. We have one of the lowest carbon emitting generation fleets in the country, with 60% of our megawatt hours coming from zero-emitting sources – nuclear and hydro.

The electric industry will struggle to formulate consistent positions on global warming and there will be challenges for some players as individual states race ahead of Washington but we believe the accelerating pace of discussions is healthy for everyone concerned and gives us reason to be optimistic about our own future.

Turning to slide 10…

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Developing Option for New Nuclear

• Focus on maintaining option to pursue new nuclear opportunity through removing obstacles and mitigating risks

• Constellation well-positioned to take advantage of potential nuclear renaissance

Time

Technology CertaintyStandby Default Coverage

Production Tax CreditLoan Guarantees

Regulatory CertaintyCredit Rating Agency Impact

Project Financeable

Energy Policy Act

Financing

Risk Profile 2005

Potential Risk Profile in Future

We are also cautiously optimistic about the future for new nuclear generation capacity in the United States. We believe that the debate around environmental policy and U.S. energy security are very supportive of a nuclear renaissance. However, there are a number of significant obstacles and risks between where we stand today and where we need to go before new nuclear capacity will be built.

Our approach to this opportunity is the same as with other opportunities we evaluate: First, we try to leverage our existing skills to identify an area of market opportunity, Second, we try to thoroughly understand the risks involved, Third, we mitigate or eliminate unwanted risks, and fourth, we apply a gated risk management approach that allows for multiple off-ramps before we commit large amounts of capital. Our approach to new nuclear is the same.

In the near-term, our focus will be developing the option to pursue the new nuclear opportunity. We expect to keep capital investment relatively modest over the next couple of years as we work to remove obstacles and mitigate risks. We believe our unique business model, the alignment with AREVA, Bechtel and EdF, and strong nuclear operating expertise position us well to take advantage of a potentially large, developing opportunity. Further, we are working with several parties similarly interested in new nuclear plants who share our perspective and who are teaming with us in our approach.


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Perspective on Competitive Markets in 2006• Competitive market structure woven into fabric of U.S. economy• Benefits of competition are well documented

– Competition has resulted in $34 billion in savings to residential customers nationwide (1)

– Fuel-adjusted prices in PJM declined by one-third between 1998 and 2003 (2)

– In markets with well-structured retail choice options, approximately 90% of large customers and almost 50% of medium size customers have switched to competitive suppliers (3)

• Competition continued to progress despite noise and drama caused by expiration of rate caps, rising commodity prices and election-year politicking

• Future growth opportunities likely through further deregulation – Federal support and evidence of customer savings will continue to push deregulation

forward– Competitive supply platform scale and cost advantage will favor Constellation in opening

markets

(1) Source: Cambridge Energy Research Group; (2) Source: Synapse Energy Economics; (3) Constellation estimates.

• Benefits of competition well documented• In 2006, competition continued to move forward, despite political noise and drama • Further deregulation favors Constellation’s competitive position

Over the years, we have been strong proponents of competitive markets, not only because it benefits our business model but because it is good public policy. Competition in energy markets is woven into the fabric of the U.S. economy, and its benefits are well documented. A CERA study found that competition has resulted in $34 billion in savings to residential customers nationwide. Another study found that fuel-adjusted prices in PJM declined by one-third between 1998 and 2003. In markets with well-structured retail choice options, approximately 90% of large customers and almost 50% of medium-size customers have switched to competitive suppliers. These facts support the notion that customers continue to benefit from well-functioning competitive markets.

Last year, the confluence of expiring rate caps, rising commodity prices, and election-year politicking increased the noise and drama surrounding deregulation and caused some to question electricity market restructuring. However, competition continued to progress in the face of these challenges. For example, Illinois successfully completed first-time wholesale auctions, Pennsylvania is beginning to address the transition to market prices for residential customers, and commercial and industrial customers petitioned the California commission to lift the suspension on customer choice.

Our projections contemplate the state of competitive markets as they stand today, including existing plans in some states for continued migration towards competitive markets. It does not contemplate new opening of additional markets, but should other states begin the deregulation discussion, we are clearly positioned to benefit. Federal support for deregulation and substantial evidence of customer savings will continue to push deregulation forward. The scale and cost advantage of our competitive businesses leave us well-positioned to deliver more growth in future years.


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Maryland Update• Confluence of events in Maryland in 2006 unlikely to repeat in future

• Current political and regulatory environment appears to be stabilizing– PSC succession now proceeding

– Full recovery of BGE costs was assured

– Securitization approved

– Customers scheduled to transition to market rates in 2007

• Healthy Air Act clarifies rules and provides certainty to targets and timelines– Constellation positioned to meet emissions requirements

• Maryland political environment appears to be stabilizing

• Expect constructive dialogue with political leaders and regulators

The confluence of events that led to the political drama in Maryland in 2006 is unlikely to repeat in the future. The current political and regulatory environment appears to be stabilizing and succession in the Public Service Commission is now proceeding. Looking through the noise of last year, it is important to understand the facts that transpired. Full recovery of BGE’s costs was assured by the legislation passed in the special session last summer, securitization of rate deferrals has been approved, and customers are scheduled to transition to market rates this year, with an interim “opt in” plan to be approved by the public service commission in the coming months.

I have spent time with the new governor and the presiding officers over the past weeks. I believe we do have a constructive dialogue and that will continue in the coming months, and I also expect that there will be a few bumps in the road as we transition to market prices.

I know many of you are focused on the environmental regulations and capital requirements for compliance, and Follin will address this a little bit more later. We now have legislation that clarifies the rules and provides defined targets and timelines. We have specific plans in place to become fully compliant and expect to meet the deadlines as required.


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Attractive Long-term Growth Drivers

Supportive Long-term Commodity Price Outlook

Fundamental Growth Drivers

• Expiring hedges established 2 - 4 years ago drive earnings growth through 2009 and beyond

• Expiring Nine Mile Point PPA in 2009 and 2011

Roll Off of Below-Market Hedges

• Disciplined investing in above hurdle-rate projects• Investment opportunities in upstream gas, possible

new nuclear generation capacity, and regulated transmission & distribution

Capital Investment Opportunities

• Reducing outage days and increasing reliability• Increasing plant capacity through uprates• Lowering workforce costs

Productivity Initiatives

• Integrating wholesale and retail competitive supply platforms will optimize delivery infrastructure and improve risk management

• Lead to lower costs and streamlined processes

Competitive Supply: Increasing Market Share and Leveraging

Scale

Looking to the future, Constellation’s long-term growth prospects remain very bright. The long-term commodity price outlook has favorable implications for the value of the fleet. We tend to hedge out 2 to 4 years into the future. When below-market hedges established in lower commodity price environments roll off, we replace them with new hedges. Consequently, our gross margin will continue to grow for several years as we benefit from the high levels of commodity prices.

We offer a superior customer value proposition as an intermediary in Wholesale and Retail Competitive Supply, which should drive continued growth.

Our productivity initiatives are working and have proven sustainable. We’ve executed our plan as promised and have added $97 million pre-tax annually to our bottom line since we began our productivity initiatives in 2003. This means we’ve grown earnings by more than 10% since 2003 through streamlining our processes and investing capital to increase the output of existing plants. We have laid the groundwork in 2006 to achieve our productivity results in 2007 through reducing Nine Mile Point workforce costs and completing a 17 percent capacity uprate at Ginna.

We generate strong cash flow, and now plan to take advantage of capital investment opportunities for the future benefit of our shareholders.


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Solid Execution has Yielded Superior Investor Returns

(50%)

0%

50%

100%

150%

200%

250%

10/31

/2001

12/31

/2001

12/31

/2002

12/31

/2003

12/31

/2004

12/31

/2005

12/31

/2006

CEG

S&P Electric Utility Index

S&P 500 Index

Our merchant divisions have enjoyed great success given:• Limited exposure to the rising commodity

prices• Initially unloved business model• Few natural advantages five years ago

…based on strong performance in several separate areas:• Nuclear generation – Progress from average

single site operator to an industry thought leader with a fleet of five units

• Retail – From no presence to biggest player by wide margin

• Wholesale – From “also ran” to clear industry leader

• Acquisitions – Several moderately-sized, highly successful acquisitions

Source: Bloomberg

208%

61%

34%

I do realize that when you invest in Constellation, you put your confidence in this management team’s ability to execute. Let me put into perspective how successfulthis management team has been over the past 5 years. Since November 1, 2001, Constellation Energy has delivered stock price appreciation of 208% versus the S&P Electric Utility Index increase of 61%. Over the same period, the S&P 500 rose 34%.

In 2001, we owned a moderately-sized utility and generation assets that had limited exposure to rising commodity prices because the bulk of our generation fleet was hedged through long-term contracts. Industry players were running from the competitive supply business model. And while we had a small competitive supply business, we had few natural advantages. At that point, the future looked challenging at best…but we made the best of what we had.

First, we took a joint venture with Goldman Sachs to the industry leading wholesale intermediary. Then, we went from having no presence in the retail supply business to become the biggest player in the market by a wide margin. We moved from an average single site nuclear operator to an industry thought leader with a fleet of five units. We also made several moderately-sized, highly successful acquisitions to fill in our portfolio and solidify our position as an industry leader.

Our competitive supply capabilities and generating plant operational expertise leave us poised to be a management team who will take advantage of the opportunities this industry offers.


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Improving Return on Invested Capital

• Investing in above hurdle rate opportunities continues to drive ROIC higher• Deploying capital in a disciplined manner across the organization

6%

7%

8%

9%

10%

11%

12%

2001 2002 2003 2004 2005 2006 2007E 2008E

Total Company ROIC

WACC

2003 – 2006 Actual / 2007 – 2008 Plan

To me – the most important. We drove this success by investing in projects that delivered above hurdle-rate returns. We employ rigorous analysis and discipline to ensure we make investments that exceed their appropriate cost of capital.

Over the past several years we’ve driven our return on invested capital from a sub-par ROIC to one that is superior relative to our cost of capital and to others in the industry. We’ve gotten there through taking market share in our competitive supply businesses, driving productivity gains from our assets, making smart investments, and by eliminating sub earners from our portfolio. As we project forward, the return to profitability of our Mid-Atlantic fleet as below-market hedges roll off will accelerate the improvements we have made to ROIC. The ability we have demonstrated in driving returns will hold us in good stead as we launch into the next phase of growth for this company.

Turning to slide 16..

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Entering New Era of Growth• Constellation entering new era of significant investment to drive

growth– Spending for environmental compliance through 2010 will be significant

– Initial success of upstream gas business gives us confidence in further capital deployment

– Increasing investment in BGE plus significant potential incremental opportunities to fuel future BGE growth later in the decade

– Modest capital spending to develop option for nuclear renaissance

• Expect to continue robust dividend growth of 15%

• New investment opportunities will drive earnings growth• Dividend growth will continue to be robust

Constellation is entering a new era of growth and capital investment. Spending for environmental compliance through 2010 will be significant. With our success to date in the upstream gas business, we are placing more focus on expanding our physical asset base. We are also increasing investment in BGE for reliability. We could also see incremental investment opportunities to fuel future BGE earnings growth later in the decade. As I discussed, spending for new nuclear will remain modest over the next couple of years.

Looking forward, we believe we can deliver 15% dividend growth and continue to grow future earnings.

Now moving to slide 17 and our earnings guidance and outlook…

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Robust Long-term Earnings Outlook

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

See Appendix

• Business outlook for Constellation Energy remains robust• Reaffirming guidance for 2007 and 2008• 2009 adjusted EPS growth of approximately 10% over 2008

2.89

3.61

5.25 - 5.75

4.30 - 4.65

$2.50

$3.50

$4.50

$5.50

$6.50

2005 2006 2007E 2008E

Adju

sted E

PS (1

)

Compound Annual Earnings Growth of 22% - 26%

Our long-term outlook continues to strengthen and as you will continue to see throughout this presentation, the drivers are highly visible. We are reaffirming our guidance for 2007 and 2008. Looking to 2009, we expect EPS growth of 10% over 2008.

With that, I would like to turn the time over to Tom Brooks to discuss the outlook for our competitive business…

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Strategic Overview of Competitive Businesses

Tom BrooksVice Chairman, Constellation Energy

Thanks Mayo and good morning everyone and thanks for joining us.

I’m going to provide an overview of our competitive businesses. As Mayo mentioned, we are in the process of combining several units into an integrated merchant organization. The purpose of this realignment is to enable us to capture maximum leverage across our operations. In the last five years, we have been intently focused on broadening and strengthening our customer relationships, enhancing our capabilities in competitive markets, and operating our facilities more efficiently.

Given our success in building the generation, wholesale and retail components of our business, we are now turning our focus to creating value by leveraging across their activities. We think this will drive top line growth and enable better operating efficiency, and we intend to go after both. We will be developing and implementing detailed plans for this throughout 2007.

Looking forward to this realignment, I will provide a strategic overview of our competitive operations. As you’ll see, this will not conform to our current reporting approach, but will highlight the key economic drivers and present some thinking on returns.

Turning to Slide 19…

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Our Competitive Market Portfolio has Three Key Components

• Physical Assets and Customer Load Serving are sources of predictable earnings with good growth potential

• Risk Management & Investing optimizes these platforms, leveraging information edge to reduce risk, yield attractive returns, and provide growth opportunities

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

• 2007E EBITDA ($ in millions):Unhedged EBITDA $1,922Legacy hedges* (916)Hedged EBITDA $1,005

*NPV of all hedges (2007-2021 ): -$2.2 billion, after-tax

• Market leading load risk management business, providing electricity and natural gas products to a stable base of customers throughout North America.

• 2007E EBITDA: $402 million

• Risk management & investing platform with proven capabilities: Managing Constellation’s price risk, trading and investing in assets closely related to our physical customer businesses.

• 2007E EBITDA: $342 million

Physical Asset Base Customer Load Serving

Risk Management and Investing

See Appendix

Our competitive market portfolio includes three categories of investment and commercial activity -- our physical asset base, our Customer Load Serving businesses, and our Risk Management & Investing activities.

First, our physical asset base is comprised of 8,700 MW of mostly baseload plants located in central New York and southeast PJM. Our operations teams focus on maximizing the contribution from these units by making operational improvements that increase output and gross margin or create O&M savings. We have also consistently hedged price risk to reduce uncertainty in our earnings. Accordingly, we expect to see significant improvement in our fleet’s results over the next five years as historic hedge pricing transitions to current market levels. For 2007, we’ve forecasted unhedged EBITDA of about $1.9 billion and hedged EBITDA of about $1.0 billion, we expect hedged EBITDA to increase by a CAGR of 11% through 2011, adding $1.19 of EPS.

Second, our customer load serving businesses are the clear market leader in providing electricity and natural gas supply and risk management products to a stable and growing base of wholesale and retail customers across North America. These businesses have reached a critical level of scale, which we expect to leverage as we integrate across the platform. We expect 2007 EBITDA of $402 million from our customer load serving businesses.

Third, our risk management and investing activities have produced consistently strong performance over the last five years. Managing our own risks effectively is core to our strategy, but this is not just a defensive tool. It has also enabled us to identify and execute on a range of opportunities to deploy capital at very attractive returns, extending the scope of our customer businesses. We expect EBITDA of $342 million from these activities in 2007.


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• Physical Asset Base

• Customer Load Serving

• Risk Management & Investing

Let me now talk in more detail about each area, turning first to our physical asset base on starting on slide 21…

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Constellation’s Physical Asset Base and Load Serving Presence

• A complementary combination of physical assets and customer businesses in the restructured markets in North America

Our generation fleet is mostly low-variable cost baseload plants in high value markets with good long term prospects. Over the past five years, we have significantly improved our fleet’s operating efficiency, driving toward top quartile performance at our fossil plants and top decile on the nuclear side. We’ve made good progress, but there is more to come. As we continue to sharpen our execution, driving and sustaining both top-line productivity and operating efficiency, we expect more operational upside, complementing the market upside we see over the next several years.

We‘ve been selective and successful in our new investments in generating assets. For instance, Nine Mile Point and Ginna were very effectively integrated into our fleet model and are yielding attractive returns. The completion, start up and management of our legacy gas plants through a tough period in the capacity cycle was also well executed. As you know, we recently sold most of our gas-powered generation. Certainly this reflects something importantabout our investment philosophy. Power plants are complex facilities with substantial employee bases – you don’t buy and sell them like NYMEX gas contracts. On the other hand, we do focus intently on returns and value, so we’re not reluctant to realize value and redeploy the proceeds at higher returns when compelling opportunities arise.

In the future, we expect to continue to be active but selective investors in generating assets. For instance, our efforts to establish a new nuclear development platform have been fairly visible. Less visible but equally important is our intent to respond to the need for new generation close to home in southeastern PJM over the next several years. Additionally, as the progression of the capacity cycle yields opportunities, we do expect to pursue acquisitions of existing fossil and nuclear facilities, continuing our selective approach.


22

22

Drivers to Fleet Results: Unhedged EBITDA

• Ability to achieve operational efficiencies and sustained productivity will drive us toward top quartile at our fossil fleet and top decile at our nuclear fleet

Operational Efficiency

• Realized fuel costs driven by underlying commodity prices, transportations costs, emissions costs

• Fuel source and type flexibility

Delivered Fuel Price

• Introduction of PJM’s Reliability Pricing Model

• Declining reserve margins

• Market effect of new investment

Capacity Price

Sources of VariabilityDriver

• Spot congestion, driven by demand, generating unit performance, transmission system performance, and regulatory policy

Locational Basis Price

• Realized energy prices driven by spot fuel prices, demand, generating unit performance, transmission system performance, and regulatory policy

Hub Energy Price

• Outage execution

• Forced outage rate

• Market impact is limited, given low variable cost baseload fleet

Production

Ope

ratio

nal D

river

sM

arke

t Driv

ers

We plan to provide increasing visibility into the value of our generation fleet on a hedged and unhedged basis. To this end, I’m going to discuss the fundamental economic drivers to our fleet’s results and the hedging effects separately. Given that our fleet is comprised largely of baseload assets, only a few factors explain most of the potential variability in our unhedged EBITDA:

These are: (1) Our fleet’s production, in both energy and capacity products, principally driven by our planned outage performance and forced outage rate, (2) the ability to achieve operational efficiencies and sustained productivity as we drive towards top quartile performance at our fossil fleet and top decile performance at our nuclear fleet, (3) the price of energy at the liquid hub, which will obviously be driven by a number of market factors, (4) basis differential between the hub and the actual location of our plants – with about half of our capacity is located in the relatively constrained southeastern PJM, we tend to benefit from our plants locations relative to the hub price, (5) capacity pricing, which has become increasingly important with the enhancement of capacity markets in New York and PJM, and (6) delivered fuel prices, which are subject to varying costs for the commodity, quality variability, transportation method, and emissions. These are the most important factors that we focus on in forecasting and managing realized value.


23

23

Drivers to Fleet Results: Unhedged and Hedged EBITDA

• As hedge levels rise to today’s market levels over the next five years, we expect to see significant improvement to our fleet’s results

Given our conservative forward hedging approach, addressing economic drivers and hedging effects separately is a key to understanding the fundamental value of our fleet and its outlook:

NPV of all hedges (2007 to 2021): ($2.2) billion, after-taxSee Appendix

$ 1,351

(510)

1,861

(773)

$ 2,634

52.0

2010E

$ 1,443

(635)

2,077

(740)

$ 2,817

51.9

2009E

$ 1,507$ 1,272$ 1,005Hedged EBITDA

(293)(978)(916)Hedge Impact

1,8002,2501,922Unhedged EBITDA

(703)

$ 2,953

52.3

2008E

(701)

$ 2,622

51.0

2007E

(801)O&M

$ 2,600Total Unhedged GM

52.3Total Output (MM MWh)

2011E($ in millions)

Shifting from the drivers of results before hedging to a discussion of our hedging approach, we have followed a consistent practice of forward hedging the value of our fleet’s output to enable more predictable earnings. We have done this to support financial strength over the whole commodity price cycle, and the approach contributed to the steady trend in our earnings and improvement in our balance sheet over the last five years. At this point in the commodity cycle, after a four-year upward price trend, our hedge portfolio is naturally “out of the money”, so historic hedging somewhat masks the fundamental value of our fleet, an effect that would diminish over the next few years.


24

24

Drivers to Fleet Results: Improvement as Hedge Prices Approach Market Levels

• The transition of historic hedge pricing to current market levels will increase reported EBITDA over the next five years

• Over this transition period, a multiple of unhedged EBITDA less the NPV of hedges probably best reflects the fleet’s economic value

See Appendix

$0

$500

$1,000

$1,500

$2,000

$2,500

2007E 2008E 2009E 2010E 2011E

$ in

Mill

ions

Hedged EBITDA Unhedged EBITDA

The gap between our results before and after hedging will diminish significantly as hedged EBITDA increases over the next five years, which you see here as the narrowing of the yellow wedge. We forecasted unhedged EBITDA based on prevailing forward prices in mid December, so the forecasted decline in unhedged EBITDA over the 2008 to 2011 period is simply a reflection of the shape of today’s backwardated forward curve. Of course, this effect could ultimately play out differently if declining reserve margins cause power prices to increase in the future relative to current forward market levels.

As with any portfolio managed with a consistent hedge program not biased toward trying to predict future prices, we would expect our average realized price per MWH after hedging to lag market prices after the extended period of rising prices that we have experienced over the last four years. Conversely, we would expect that the average realized price of our portfolio would outperform market prices after an extended period of declining prices. Most importantly, over the long term, we would expect our results after hedging to yield a realized average price in line with the market over the full cycle, implying a long run average value of our hedge portfolio of about zero.


25

25

Longer Term Drivers: Effects of Tightening Reserve Margins

Capacity Value:• Declining reserve margins have motivated a shift in

regulatory policy toward encouraging new generation with enhanced capacity markets

• About half of Constellation’s fleet is located in Southeast PJM, which will need new capacity and where a significant block of existing capacity may need environmental upgrades. These conditions could cause upward price pressure from current forwards

Scarcity Pricing:• Current regulatory policies tends to suppress energy

prices at times of scarcity through offer price caps, market dispatch rules and real-time price mitigation

• These policies may need to be restrained somewhat in order to attract needed new investment, which could cause average energy prices to increase

• Declining reserve margins may yield additional value in the form of capacity and energy prices

PJM Heat Rate vs. Reserve Margin

8

8.5

9

9.5

10

10.5

11

11.5

12

2007 2008 2009 2010

Hea

t ra

te (

MM

Btu

/M

Wh

)

0

5

10

15

20

25

30

35

40

Res

erve

Mar

gin

(%

)

Heat Rates Reserve Margin

PJM Classic Reserve Margin Forecast

0

10000

20000

30000

40000

50000

60000

70000

80000

2007 2008 2009 2010 2011 2012 2013 2014M

W

0

5

10

15

20

25

30

35

40

Res

erve

Mar

gin

(%

)

Capacity Additions Peak Demand Reserve Margin

Looking forward, there may be additional upside to our outlook due to declining reserve margins and their impact on regulatory policy These factors could create price pressure in either capacity or energy prices.

In PJM, a new approach to locational capacity markets has been recently approved, though subject to re-hearing by the FERC. We can not yet project capacity prices with any precision, given that the rules implementing the RPM program have yet to be developed. However, Southeast PJM, the location of about half of our capacity, is supply constrained and has a number of units that may require capital upgrades to meet new environmental standards. As a result, we think there may be upward pressure on the clearing price of Southeast PJM capacity, since under the RPM program supplier offers are capped at a level that is in part driven by incremental capital investment. We have forecasted capacity prices at the prevailing forwards in late December (for instance, about $40/MW day in PJM and $90/MW day in New York for 2007). Therefore, over the next five years, there could be upward pressure on capacity prices from our forecasted level if capital upgrades are made to enable older plants to continue operating, or if older plants are replaced by new ones.

If we do not see new investments driving the near-term price of capacity upward, then energy prices may trend upward as reserve margins decline. Like any ISO, PJM is a heavily regulated market. There are a number of features of this regulation that effectively suppress energy prices at times of actual scarcity: offer price caps, market dispatch rules, and real-time price mitigation. In the last several years, generation reserve margins have been declining with little announced new investment. In the long run, regulatory policy may need to adjust to allow actual scarcity to be reflected in energy market prices in order to attract new investment, if the new capacity market alone proves insufficient to attract new investment. If this policy transition were to happen, our fleet would likely benefit in the long run.


26

26





Let me now turn to our customer load serving activities starting on slide 27…

27

27

Customer Load Serving: Customer Value Proposition

Critical Factors:• People• Technology• Information

Constellation Advantage: Risk Management Capability

Relevance:• Lowers cost to manage risk• Lowers per unit SG&A expense

Constellation Advantage: Scale

Market-leading customer solutions

Customer Need: Managing risk of energy supply cost in a complex environment

Sources of Risk:• Prices of energy, capacity and

ancillary services• Uncertain demand• Hourly balancing• Weather• Supplier performance• Grid performance• Regulatory changes

Quality Cost

Advantages that took 10 years to build

Cal'07 Power & Gas (1/06 -12/06)NYMEX vs. PJM West (24x7)

$6$7$8$9

$10$11

J F M A M J J A S O N D

$/M

Mb

tu

$40

$50

$60

$70

$80

$/M

Wh

NYMEX PJM West

Our customer load serving operations provide risk management products to wholesale and retail consumers of electricity and natural gas. Our customers value our services because energy prices are an important cost component, and managing the range of risks associated with procuring a load following product is highly complex. Our customers have recognized that it is more efficient to purchase these risk management services from us than to self-provide.

Our success in serving our customers depends on the effectiveness of our risk management approach, the quality of our presence in several customer sales channels, our focus on customer service, and our scale. We have built an edge in all four areas by investing heavily in people and technology. Over the last ten years, we have assembled the top team in the business, a team that competes confidently with both large energy companies and financial players of several types. On the technology side, we have spent ten years developing the infrastructure that supports a competitive advantage in mining and managing information resources. Together, the combination of people and technology supports a culture of excellence.

We have become a clear market leader in a substantial business, and we believe we can extend our advantage. Over the last five years, aggregating scale and driving the top line have been our prime directives. Given our success in building scale, we believe we can now drive further growth to top and bottom line by integrating across our platforms. This will put better tools and information in the hands of our salespeople who provide risk management solutions to our customers, and enable better back-office functionality at a lower cost. We are still quantifying the benefits, but we are confident this can have a meaningful impact. By combining people, scale and information with better products, better risk management and more operational leverage, we believe we can continue to lead the market and drive growth.


28

28

Constellation Load Serving Market Performance

• Given ten years of history providing risk management products to load customers, we have a good understanding of customer needs and market dynamics, as well as a strong basis for projecting future performance

Our load businesses have a substantial history of steady market performance in regard both to sales volumes and margins:

Drivers:• Our cost position enables us to compete very

effectively in utility load auctions• High retail renewal rates (power: 70%-80%; gas:

90%-95%) provide stability in customer base• Our total share of nearly 25% (1) of a fragmented

market has the potential to grow, particularly as retail switching rates increase

Drivers:• We have seen some cyclicality in unit margins,

driven by competitor behavior as well as absolute energy price levels

• While we maintain strict pricing discipline, our focus on being the low cost provider has allowed us to generate attractive returns under all market conditions

(1) Retail power market share as of year-end 2006

01020304050

2004 2005 2006

Pea

k M

W (

'000

)

0

100

200

300

400

(mill

ion

mm

Btu

)

Power Gas

$0.00$1.00$2.00$3.00$4.00$5.00

2004 2005 2006

$/M

Wh

$0.00

$0.05

$0.10

$0.15

$0.20

$/m

mB

tu

Power Gas

Focusing on key indicators of our market performance, we have been providing risk management products to load serving customers for ten years, so we have a good understanding of customer needs and market dynamics, as well as a long history to inform our projections of future performance.

Here is a summary of our last three years of market performance as to sales volumes and unit margins. We have experienced steady growth in sales volumes. Key drivers include: our success in utility load auctions, where our lower cost to manage risk across a big portfolio allows us to compete very effectively, high renewal rates of 70% to 95% in our retail channels, and our ability to continue growing our current market share of nearly 25% in a fragmented market, particularly as retail switching rates increase.

As to margins, we’ve been able to increase unit margins in natural gas by transitioning our product mix toward higher value risk management products. On the power side, we have seen some cyclicality, driven by competitor behavior and market conditions, but we have also found that by maintaining strict pricing discipline we have been able to maintain attractive returns under varying conditions.


29

29

Customer Load Serving: Results and Outlook

• Our load platform has become stable, predictable and relatively large

• 2007 EBITDA forecast: $402 million (18% growth over 2006)

• We see long-term growth opportunities based on adding share in existing markets, expanding into new geographic markets, further penetrating the unswitched retail market, and capturing more efficiency by integrating across our full load-serving platform

• Our customer load serving business is stable and predictable with plenty of growth potential still to be captured

See Appendix

Gross Margin Summary

$0

$500

$1,000

$1,500

2005 2006 2007E

$ in

Mil

lion

s

Realized Gross Margin Future Year Backlog Creation

EBITDA

$0

$200

$400

$600

2005 2006 2007E

$ in

Mill

ions

Given our market leading position and steady demand, our customer load serving operations have experienced strong growth. We project EBITDA of $402 million in 2007, an increase of 18% over 2006, and we see meaningful longer term growth based on adding market share, further penetrating the unswitched retail market, and capturing more efficiency by integrating across our load serving platform.

Our customer load-serving activities have also generated very attractive returns on investment. Anticipating the upcoming realignment of our merchant organization, we have made an initial cut at the proportion of Constellation’s current equity capital required to support a combined wholesale and retail customer load serving business. On this preliminary basis, the combined platform’s requirements would be in the range of $600 million to $800 million. Based on this pro forma equity requirement and our 2006 EBITDA of $341 million, we earned an ROE 26% to 34% in 2006. Our return outlook for 2007 is higher. Since, this is just a preliminary look at the combined equity capital requirements, we will be refining our assessment as part of planning and implementing the realignment.


30

30





Let me turn to a discussion of our risk management and investing activities starting on slide 31…

31

31

Risk Management & Investing• Our risk management platform has become a

clear differentiator, built on intense focus on detail, sophisticated analytics, and an absolute commitment to performance

• Activities include:– Customer Business

Non-load powerUpstream & downstream gasCoal & freight

– Portfolio Management associated with Load Serving and RM&I positions

– Trading

• 2007 EBITDA forecast: $342 million (favorable 2006 PM result not forecast to continue)

• Estimated 2006 ROE: Approximately 30%

• We expect our risk management and investing activities to continue enabling predictable results throughout the commodity cycle and to provide opportunities to invest capital at attractive returns

See Appendix

Gross Margin Summary

$0

$500

$1,000

2005 2006 2007E

$ in

Mil

lion

s

Realized Gross Margin Future Year Backlog Creation

EBITDA

$0

$200

$400

$600

2005 2006 2007E

$ in

Mill

ions

Our Risk Management & Investing activities have been crucial to our success for two reasons. First, our commercial approach is built on thoroughness in identifying, analyzing and managing risks. The predictability of our results in volatile markets resulted in part from the strong performance of this area. An intense focus on risk management runs right through our culture, and we think it sets us apart.

In addition, this capability has been a source of opportunities to invest capital at very attractive returns and has allowed us to incubate opportunities that have broadened our platform and driven growth. These investment areas include: (1) our customer businesses in non-load serving power products, upstream and downstream natural gas, and coal & freight services, (2) the portfolio management associated with all of our wholesale activities, and (3) Trading and related activities. Anticipating the realignment of our merchant segment, we also carried out a preliminary assessment of the equity capital supporting our Risk Management & Investing activities. On a preliminary basis, the range is $900 million to $1.1 billion. In 2006 we earned $553 million in EBITDA from these activities, implying an ROE range of 30% to 37%. While we don’t expect to match those results every year, we have earned consistently attractive returns in the past, and we expect this pattern to continue in the future.

We know that this category of activity, unlike our physical asset fleet and load serving, is challenging to model from the outside, but it has been a steady earner, and the underlying capability is a key differentiator that has been critical to our success.

Since we have been an active investor in natural gas production in the last year, let me turn to that area as it provides a good example of the approach we employ within our risk management and investing operations.


32

32

Risk Management and Investment: Natural Gas Production

• Constellation leverages strong technical skills and experienced partners to create a portfolio of discrete investments with attractive rates of return

Upstream Investment Focus

Early Stage Development Mature

Time

Asset Lifecycle

CEP Focus

Joint Focus

Constellation Focus

0

% D

evel

oped

100

• Develop properties and hedge production to lock in returns

• Market knowledge supports broader Constellation business

• Leverage risk management and risk valuation expertise to identify investment and partnership opportunities

• Monetize investments through dropdown sales to CEP or third-parties

• Return cash to Constellation

Harvest

Portfolio Development &

Management

Strategic Investment

Upstream Investment Strategy

We follow a very structured, targeted approach to investing in natural gas production.

First we identify investment opportunities that are strategically aligned with our broader business objectives and core competencies, tending toward lower production risk, long-lived reserves where our commodity price management expertise is important. We partner with companies experienced at reserve development and extraction, who can benefit from our risk management expertise, and we combine our own internal valuation capability with external expertise to evaluate and structure investments.

After we invest, we focus on maximizing the value of the assets within our portfolio by improving hedging approaches, development strategies and operations.

Finally, we look for opportunities to realize returns by monetizing investments after enhancing their value. As many of you are aware, we recently created a tax-advantaged vehicle with our IPO of Constellation Energy Partners. CEP is structurally similar to the MLPs that are prevalent in the mid-stream business. The IPO enabled us to harvest cash for future investment while retaining a stake in CEP, which should help support our targeted natural gas strategy. The two companies have a complementary investment focus that allows us to pursue joint acquisitions of properties and provides Constellation with a ready partner for certain types of properties after we have improved them, which should allow us to efficiently monetize some investments in the future through dropdown sales to CEP.

When we see attractive opportunities that fit our targeted strategy, we expect to continue investing in natural gas production. We have made nine acquisitions over the past four years, investing about $500 million dollars at attractive returns. Given our track record of success and the advantage of the CEP relationship, we expect more success from this focused approach.


33

33

Summary and Outlook• Key characteristics of our competitive businesses:

– Valuable baseload assets in attractive markets, operated efficiently, with more to come– Market-leading load-serving businesses with strong track record, deep customer

relationships, and good growth prospects– Proven, return-oriented risk management approach

• Over ten years, we have built competitively advantaged customer businesses based on:– People– Technology– Scale

• Our competitive businesses have generated attractive returns on capital, which are expected to improve over the next several years as hedge price levels increase and we build on our successful track record in load serving and risk management and investing.

• In realigning our merchant platform, we see opportunities to drive top line growth as well as operating efficiencies

• Our constant focus on generating attractive risk adjusted returns on capital will remain core to our strategy

To summarize, our competitive businesses are built on a foundation of three key elements: (1) our valuable baseload generation assets in attractive markets that we have operated efficiently, and will continue improving, (2) our market-leading load-serving businesses with strong track record, deep customer relationships and good growth prospects, (3) our proven, return-oriented risk management approach.

Over ten years, we have built meaningful competitive advantages in our load serving businesses based on the quality of our team, our technology infrastructure and our scale. We believe that this edge will support continued market leadership.

Our competitive businesses have generated attractive returns on capital, which we expect to improve as hedge price levels transition to current market prices and we continue to build on our successful track record in load serving and risk management and investing.

As we realign our merchant platform, we will go after opportunities to drive top line growth as well as operating efficiencies.

And as we look forward to growth opportunities, we will maintain our constant focus on generating attractive returns on capital.

Now I’ll turn things over to Follin.

34

Financial Overview

E. Follin SmithExecutive Vice President, Chief Financial Officer and Chief Administrative Officer

Thank you Mr. Brooks. Good morning everyone. Thanks for joining us.

35

35

Agenda

• 2006 Financial Results

• 2007 and 2008 Earnings

• 2007 and 2008 Capex/Cash Flow/Balance Sheet

• Long-term Outlook

I’ll start this morning at Chart 35 taking a look at our financial results for the fourth quarter and for the full-year and then we’ll focus on the 2007 and 2008 outlook and finally we’re going to look at our capital spending, cash flow, and the balance sheet.

Finally, I’ll give you some insight into our earnings outlook beyond 2008 and some thoughts around valuation.

Starting with slide 36…

36

36

Adjusted EPS

$3.00 - $3.30Early 2006 Guidance (excl. High Desert)

(0.09)(0.01)Workforce reduction costs

$1.18$1.03Total

(0.03)0.02Merger-related costs

0.260.26Gain on sale of gas-fired generation plants (excl. High Desert)

2006Q4 2006Discontinued Operations / Special Items

$1.04$0.76Discontinued Operations – (High Desert Gain on Sale and 2006 Earnings and Panama)

$3.30 - $3.45$0.75 - $0.90October 2006 Guidance

(0.21)(0.07)Less: Economic Non-Qualifying Hedges

$3.61$1.08Adjusted EPS

(0.16)(0.04)Less: Synfuel Earnings

(1.18)(1.03)Less: Special Items$5.16$2.22GAAP EPS Including Discontinued Operations

2006Q4 2006($ per share)

Fourth quarter GAAP earnings were $2.22 per share. After special items, our fourth quarter adjusted EPS was $1.08 versus a guidance range of 75 cents to 90 cents. For the full year, GAAP earnings were $5.16 per share. We backed out $1.55 per share, including the gain on the sale of the gas plants, a reclass of High Desert earnings to discontinued operations, gains on non-qualifying economic hedges, and synfuel earnings to arrive at adjusted EPS of $3.61. This adjusted EPS is 16 cents higher than the guidance we gave you in October of $3.30 to $3.45 per share and 31 cents higher than guidance provided at the beginning of the year.


37

37

4th Quarter EPS Summary

24%$0.21$0.87$1.08Adjusted Earnings Per Share

$0.75 – $0.90Q4 2006 Earnings Guidance

N.M. 0.020.000.02Other Non-regulated(28%)(0.07)0.250.18Utility

42%$0.26$0.62$0.88Merchant%EPSQ4 2005Q4 2006($ per share)

Change4th Quarter Segment EPS (1)

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

+$0.13 New Energy

($0.05) Fleet and Other+$0.18 Wholesale Competitive Supply

Merchant Variance from 2005

Now looking at management results by segment, the Merchant earned 88 cents, well above our guidance range of 55 to 70 cents per share due to outperformance by wholesale competitive supply, primarily portfolio management and trading, and by NewEnergy. Compared to last year, EPS was up 24%, primarily due to growth in competitive supply—both wholesale and retail commercial and industrial—offset by lower earnings at BGE due to weather and higher costs.

Turning to slide 38..

38

38

Full Year 2006 EPS Summary

$3.00 – $3.30Early 2006 Guidance (excl. High

Desert)

25%$0.72$2.89$3.61Adjusted Earnings Per Share

$3.30 – $3.45October 2006 Guidance

N.M.0.05 0.010.06Other Non-regulated(14%)(0.14)1.010.87Utility

43% $0.81$1.87$2.68Merchant%EPS20052006($ per share)

Change2006 Segment EPS (1)

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

($0.08) Other+$0.28 NewEnergy

($0.39) Fleet+$1.00 Wholesale Competitive Supply

Merchant Variance from 2005

For the full year, adjusted earnings were $3.61 per share, up 72 cents or 25% from last year, and 31 cents above the top end of the guidance range provided at the beginning of the year of $3.00 to $3.30 excluding High Desert.

The merchant segment achieved EPS growth of 81 cents. Earnings benefited from $1.00 per share of growth in wholesale competitive supply, both in new business originated during the year and backlog realized. NewEnergy performance improved 28 cents, driven by better electric rates and lower costs to serve load. The fleet was down 39 cents for the year due to the end of competitive transition charge collections in Maryland, longer planned nuclear outages, primarily due to the Calvert Cliffs reactor vessel head replacement, and due to inflation. These negatives were partially offset by fleet price improvements and productivity gains. Finally, we had an aggregation of smaller unfavorable items that cost us 8 cents.

The utility’s earnings were down 14 cents compared to 2005 due to mild weather and higher operating expenses partially offset by benefits of the gas rate case that took effect in mid-December 2005.


39

39

2006 Earnings Variance Analysis

(0.26)(0.08)(0.34)Other$0.46$3.00 - $3.30 (1)$3.61 (2)2006

(0.13)(0.10)

0.15(0.22)0.080.280.73

0.27$2.89 (2)

Actual

(0.08)(0.10)

0.13(0.22)0.100.080.16

0.27$2.89

Jan. Forecast

0.20NewEnergy0.57WCS New Business

-CTC(0.02)Fleet Price

-Inflation

0.02Productivity

(0.05)BGE

-WCS Backlog-2005 Adjusted EPS

Variance

2006$3.00 - $3.30

2005$2.89

WCS Backlog 0.27

Fleet Price0.10

CTC(0.22)

BGE(0.08)

WCS NewBusiness

0.16

NewEnergy0.08

Productivity0.13

Inflation(0.10)

Other (0.08)

$2.50

$2.75

$3.00

$3.25

$3.50

$3.75

(1)Adjusted guidance removes $0.35 of forecasted High Desert earnings, which has been reclassified to discontinued operations and $0.30 of synfuel earnings(2) Excludes special items, certain economic, non-qualifying hedges, and synfuel earnings See Appendix

2006 Forecast Earnings Walk (January 2006)

Competitive Supply

($ per share)

This is the waterfall projection for 2006 compared to 2005 we shared with you last January. The bottom of the chart compares our actual performance to what we told you to expect a year ago. We told you we would grow in competitive supply and via productivity and that the end of the competitive transition charge in Maryland would create a headwind. That is what played out, with better performance by competitive supply partially offset by longer planned outages as we hit some difficulties in the Calvert Cliffs reactor vessel head replacement and an accumulation of other smaller negative variances. We executed on our plan for the 5th straight year, with outperformance in some areas far offsetting challenges in others. This is what good management teams do. They deliver what they say they will.


40

40

Agenda





I’ll start with an outlook on 2007 and 2008 earnings.

41

41

2007 and 2008 Key Financial Themes

• Mid-Atlantic Fleet return to profitability as below-market hedges roll off

• Moderate growth assumptions for competitive supply business and lower forecast PM&T

• Productivity improvements/Driving scale and efficiency

• Increased capital spending driven by environmental spending, T&D opportunities, and upstream gas investments

• Improving returns on invested capital

The most significant driver to 2007 and 2008 earnings growth will be the return of the Mid-Atlantic Fleet to profitability as below-market revenue hedges are replaced with later vintage hedges. As Tom mentioned, in effect, we are realizing 2004 vintage power prices in 2007 earnings and will recognize today’s higher power prices later in the decade.

Another key theme is the inclusion in the forecast of moderating growth assumptions for competitive supply. We’re forecasting lower wholesale portfolio management and trading results following an exceptional performance in 2006. Wholesale and retail power, we’re assuming we’ll see a return to more normal conditions from the very favorable 2006 environment. On the other hand, we have a strong backlog and expect good growth in the wholesale and retail gas businesses.

Next, productivity has been a big story for us over the past several years. Our productivity initiatives at Generation and Headquarters are on track. In addition, efficiency initiatives at NewEnergy will drive lower cost/MWh sold. And generally our gross margin will grow faster than our cost base as we benefit from scale with our growth.

A new theme beginning in 2007 will be a step up in capital spending. The drivers are environmental spending, higher spending on transmission and reliability programs at BGE, and a place holder for investments in our successful upstream gas business in 2007.

Finally, return on invested capital will continue to improve as our Mid-Atlantic Fleet returns to profitability as below-market hedges roll off and as we continue to make smart investments.


42

42

Substantial EPS Growth in 2007

Change vs. Mid-point

$0.87

0.01

(0.17)

$1.05

$

2007 EPS Outlook

$3.61

0.06

0.87

$2.68

2006 (1)

24%

(20%)

N.M.0.06 - 0.08Other Non-regulated

$4.30 - $4.65Adjusted Earnings Per Share

0.65 - 0.75Utility

$3.60 - $ 3.85Merchant 39%

%2007E($ per share)

See Appendix

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

For 2007, our guidance range is $4.30 - $4.65 per share, which represents 19% to 29% growth over a very successful 2006. We expect the merchant segment will be up 34% to 44% and BGE will be down 14% to 25%


43

43

2006 to 2007 Earnings Walk - Summary

Earnings Drivers• Generation - Mid-Atlantic Fleet returning to profitability as below-market hedges roll off and fewer planned nuclear

outage days in 2007 partially offset by end of competitive transition charge• Competitive Supply

− Wholesale down due to lower PM&T and moderating power market conditions offset by strong backlog and gas new business growth

− NewEnergy up primarily due to higher gas volumes• Net Productivity - Continued productivity gains at generation and staff partially offset by inflation• BGE – Loss of decommissioning revenue and residential POLR margin and other costs partially offset by return to

normal weather

(1) Excludes special items, certain economic, non-qualifying hedges, and synfuel earningsNote: Analysis assumes midpoint of 2007 guidance rangeNote: Generation includes Mid-Atlantic Fleet, Plants with PPA, and QFs/OtherSee Appendix

($ pe

r sha

re)

2007 $4.30-$4.65

2006 3.61

CompetitiveSupply (0.19)

BGE(0.17)

Generation 0.92

NetProductivity

0.14Other 0.17

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

$4.75

(1)

Slide 43 walks you through the factors that will contribute to our 2007 earnings growth.Generation profits will grow by 92 cents in 2007 driven primarily by the 83 cents per share affect of the improvement in fleet price and the 20 cent impact of fewer planned nuclear outage days in 2007. These positives will be partially offset by the negative 14 cent impact of the end of the competitive transition charge.Our competitive supply businesses are forecast to be down 19 cents in 2007, with a decrease in wholesale profits to be partially offset by an increase in NewEnergy's profits. First, we’re forecasting a significant decrease in wholesale portfolio management and trading which had a banner year in 2006. Second, in wholesale power, a monetized contract added to profits in 2006 and, in general, we saw very robust new business conditions in wholesale power. Accordingly, we are assuming 2007 power results will be down with the assumption of a more normalized environment. On the other hand, wholesale backlog is $150 million higher going into 2007 than it was in 2006, and we expect to see good new business growth in gas. With respect to retail, EBIT will be up as the gas business projects an increase of about 1 percentage point in market share, with about 74% of planned volumes already contracted. The retail electric business picks up volume in markets transitioning at the beginning of 2007, namely IL, CT and PA. Sixty-six percent of electric plan volume is already contracted, slightly ahead of where we were this time last year. The profit impact of the electric volume pick up will be offset by an assumption that we trend back to normalized unit margins after a very favorable 2006 environment.Continued productivity gains of 22 cents in 2007 will be partially offset by 8 cents of inflationary cost increases, resulting in a net earnings increase of 14 cents. BGE’s earnings will be down 17 cents. The main drivers are associated with last year’s Maryland legislative actions, which in aggregate cost us 9 cents, and 15 cents for an accumulation of smaller items. These negatives will be partially offset by a favorable 7 cents due to our forecast assumption of a return to normal weather. In other, the primary drivers are lower interest expense partially offset by the absence of gas plant earnings excluding High Desert.Now, turning to slide 44..

44

44

Highly Visible Mid-Atlantic Fleet Earnings Growth

$20

$30

$40

$50

2004 2005 2006 2007E 2008E 2009E

Gro

ss M

arg

in/

MW

h

Average Gross Margin / MWh (Mid-Atlantic Fleet)

• Philosophy of maintaining a highly hedged fleet has delayed earnings increase resulting from higher commodity prices

• Highly hedged fleet creates significant visibility into our future years’ earnings

As Tom pointed out, a consistently applied hedge approach will mean some years, hedges are in the money, and some years hedges are out of the money, but over time should not cost shareholders anything. The reason we maintain a highly hedged portfolio is to create visibility for our investors and our employees as we manage to our competitive supply and productivity growth targets. In a rising price environment, the upside is a delayed gross margin uplift. The converse will hold true in a declining price environment. This graph represents gross margin per megawatt hour from our Mid-Atlantic fleet from 2004 through 2009. Our gross margin from the fleet was declining through 2006 as a significant portion of our revenues had been hedged in 2001 in conjunction with Maryland deregulation, while fuel costs were not locked in. But early in the decade, our coal prices went up while revenues were fixed, squeezing our margins. Going forward, gross margin per megawatt hour will improve as our below market hedges roll off and our Mid-Atlantic fleet returns to appropriate earnings. This gross margin is highly hedged through 2008, which provides significant visibility into our future earnings.


45

45

Competitive Supply Growth

See Appendix

• Forecasting healthy growth in retail load serving and good wholesale gas and coal growth• Forecasting lower PM&T results in 2007 following exceptional performance in 2006

$0

$500

$1,000

$1,500

2003 2004 2005 2006 2007EG

ross

Mar

gin

($

mill

ion

s)Wholesale Competitive Supply (Power, Gas & Coal) * Retail Competitive Supply (NewEnergy) Wholesale Competitive Supply (PM&T)

$473

$649

$818

$1,309 $1,303Compound annual growth in non-portfolio management and trading competitive supply of 30% from

2003 to 2006

* - Excludes Holland and Rio Bravo gas plant gross margin

This slide divides our wholesale and retail competitive supply results into three categories. In the dark blue, you can see that Wholesale Competitive Supply before portfolio management and trading has achieved steady growth by taking market share in power load serving and developing complementary gas and coal businesses.

In the light blue, you see the growth in NewEnergy, our power and gas business which serves commercial and industrial customers. The combination of wholesale power, gas and coal and commercial and industrial power and gas has grown at a compound annual growth rate of 30% from 2003 to 2006.

For 2007, we are forecasting a moderating growth rate of in this grouping of competitive supply activities. We are forecasting healthy growth in wholesale gas and coal, supported by good backlogs. Wholesale power is forecast to have profits about unchanged from 2006 levels. We monetized a contract , which triggered a gain in 2006 and we had robust market conditions. We are not forecast these to recur, but we do have a strong power backlog. We expect strong growth in NewEnergy’s volumes driven by strong switched market performance as customers elect to leave utility service contracts as they expire and take advantage of lower electricity provided by deregulated providers.

The green portion represents wholesale portfolio management and trading. Including portfolio management and trading, our 2003 to 2006 competitive supply growth rate was 42% per year. As the size of our portfolio increases, we are finding more opportunities to generate portfolio management and trading earnings. However, we think it is prudent to project lower year-over-year PM&T earnings following our exceptional performance in 2006.

In total, we are forecasting competitive supply to be slightly lower in 2007. In essence, growth in combined backlog and gas businesses will be more than offset by an assumption that portfolio management and trading and power will not repeat their incredibly strong 2006 performances.


46

46

Driving Additional Profits from Productivity

• Since announcing our long-term productivity initiatives in 2003, we have added $97 million pre-tax to ongoing annual profits

• Expect to deliver incremental $83 million in permanent productivity gains in 2007 and 2008– 2007 productivity primarily driven by Nine Mile Point labor realignment and 83MW Ginna output

uprate both completed in late 2006• On average, productivity gains will drive approximately 2% per year of annual EPS growth from 2004

through 2008

(100)

(50)

0

50

100

150

200

2004 2005 2006 2007E 2008EP

re-T

ax E

arn

ings

($

mill

ion

s)

Realized Target

(40)

50

97

157 - 162 170 - 180

In addition to our strategy to leverage our leadership position as commodity intermediaries, we focus intensely on driving productivity each year by developing specific targets and detailed plans and then crisply executing to what we’ve outlined. As you’ll recall, in 2004 we promised that 2008 pre-tax earnings would be $150 - $180 million higher than 2003’s due to our generation and staff productivity initiatives. This chart shows our cumulative gains as a result of our productivity initiatives.

2007 productivity gains will largely be the result of already completed 2006 initiatives: We will have lower labor costs from a 2006 workforce realignment at Nine Mile Point, helping to drive $30 to $35 million in 2007 productivity; and the successful 2006 implementation of the 83 megawatt uprate at Ginna will drive another $19 million in 2007.

On average, permanent productivity gains at Generation and Headquarters will have driven approximately 2 percentage points per year of our EPS growth from 2004 through 2008.


47

47

Reducing Costs as a Percentage of Gross Margin

• Total expenses as a percentage of gross margin is an important gauge of productivity and scale benefits

• Represents increased EBIT of $284 million in 2007 due to productivity and scale benefits

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2004 2005 2006 2007E 2008E

($ in

thou

sand

s)

Gross Margin

Cost with no Productivity / Scale benefits

Cost with Productivity / Scale benefits

Increased EBIT of $284 million in 2007

Not only is our bottom line benefiting from explicit productivity initiatives in Generation and Headquarters, which we talked to you most frequently about, we are benefiting from scale as we leverage our fixed costs in systems and people. This chart illustrates how we have driven productivity and scale to increase EBIT.

In 2004, our expenses were 72% of gross margin. The green line here represents holding costs as a percentage of gross margin constant at 72%. Now, with generation and staff productivity, with NewEnergy’s efforts to reduce SGA/MWhr and as gross margin growth outpaces costs, our bottom line benefits. The blue line represents actual and forecast costs. In 2007, we expect costs to be 65% of gross margin: That 7 percentage point improvement from 2004 represents an increase in EBIT of $284 million due to productivity and scale benefits.


48

48

2007 Growth Drivers Highly Visible

• Portfolio price exposures and fleet output highly hedged for 2007 so that changes in commodity prices should not significantly affect backlog and $0.83 EPS growth from fleet price improvements

– As of 12/31/2006, 96% of power length and 91% of fuel short was hedged for 2007– As of 12/31/2006, our portfolio was balanced as to price risk for 2007

Power down $1/MWh, Fuel unchanged ($0.01)Fuel down $0.10/MMBtu, Power unchanged 0.04Power down $1/ MWh, Fuel down $0.10/ MMBtu(1) $0.03

• Forecast for wholesale competitive supply assumes lower portfolio management and trading and power business after very robust 2006

• 2007 Major Productivity drivers essentially complete– 2006 Nine Mile Point workforce realignment complete– 2006 Ginna uprate complete

• The underpinnings for our strong 2007 earnings growth are in place, making our 2007 earnings highly visible

• Must execute in many areas to attain 2007 earnings projections but forecast appears reasonableNote: Percent hedged includes Mid-Atlantic Fleet, Plants with PPA’s, and wholesale and retail competitive power businesses. Does not include gas businesses or international coal business.(1) Numbers may not add due to rounding

To recap our 2007 growth story, the underpinnings for our strong 2007 earnings growth are in place, making our 2007 earnings highly visible.

First, our 2007 portfolio is highly hedged as to price risk. We have currently hedged 96% of our 2007 power and 91% of 2007 fuel. This means the value of the wholesale backlog and the 83 cents per share earnings growth from fleet price improvements should not vary much due to changes in market prices.

Second, our 2007 projection for wholesale and retail competitive supply includes significantly lower portfolio management and trading results and lower power new business than what we achieved in 2006.

Finally, the underpinnings of $60 to $65 million in productivity were in place at the end of last year.

We need to continue to crisply execute on a number of initiatives in order to achieve our 2007 projections, but the basis of our projections is very sound.


49

49

Q1 2007 Guidance

$0.61

0.01

0.38

$0.22

Actual Q1 2006

0.04 - 0.06Other Non-regulated

$0.80 - $1.00Adjusted Earnings Per Share (1)

0.30 - 0.35BGE

$0.42 - $0.62Merchant

Guidance Q1 2007($ per share)

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

• Improved Generation performance as the Mid-Atlantic Fleet returns to profitability as below market hedges roll off

• Higher NewEnergy volumes• Lower Wholesale Competitive Supply due to exceptionally strong portfolio management and trading

results in Q1 2006• BGE lower due to lower decommissioning revenue and other inflationary cost increases

Before I move to 2008, let me provide first quarter 2007 guidance. We expect first quarter earnings to be 80 cents to $1.00 per share, which is up significantly from the 61 cents of adjusted EPS we earned in the first quarter last year. In Merchant we are projecting EPS of 42 to 62 cents versus 22 cents in the first quarter last year. Generation will be up year-over-year as the Mid-Atlantic Fleet returns to profitability as below-market hedges roll off. NewEnergy will be up primarily due to higher volumes. These positives will be partially offset by wholesale competitive supply, which we are forecasting to be down year-over-year compared to an exceptionally strong portfolio management and trading performance in the first quarter of last year.

We expect BGE EPS of 30 to 35 cents, compared to 38 cents per share last year, consistent with full year expectations for BGE.

Moving to slide 50 and 2008 EPS…

50

50

2007 - 2008 Earnings Walk - Summary

Continued opportunity for growth in 2008 and beyond:• Profitability improvement in the Mid-Atlantic Fleet as below-market hedges continue to roll off will be the primary

driver of growth from 2007 to 2008• The competitive supply businesses continue to build their backlogs and provide steady new business growth• Conservatively forecasting productivity

20085.25 - 5.75

2007 4.30 - 4.65

Other(0.03)

BGE (0.07)

CompetitiveSupply

0.33

Generation0.79

$4.00

$4.50

$5.00

$5.50

$6.00

Note: Analysis assumes midpoint of guidance ranger for 2007 and 2008Note: Generation includes Mid-Atlantic Fleet, Plants with PPA, and QFs/OtherSee Appendix

($ per share)

We are projecting 2008 EPS of $5.25 to $5.75, up 23% versus the midpoint of 2007 guidance.

The Generation fleet will contribute 79 cents of earnings growth. The biggest driver will be the profitability of the Mid-Atlantic Fleet as below-market hedges are replaced with later vintage hedges.

We have projected 33 cents of earnings growth from competitive supply. Given an already healthy backlog in Wholesale Competitive Supply, we do not need any growth in our rate of new business origination for 2008 to achieve these numbers. NewEnergy is forecasting moderate share gains.

The impact of spending on reliability improvements and inflationary costs at BGE effect a 7 cent decline in earnings. We expect it will be time to proceed with a BGE electric distribution rate case no later than 2008, which will favorably effect 2009 earnings.


51

51

Impact of Capacity Market Reform• Capacity market enhancements have been approved by the FERC

– Reliability Pricing Model (RPM) may add to revenue from our generation plants in PJM

• Capacity position includes owned and purchased capacity less sold capacity– Constellation’s generation plants in PJM and New York produce approximately 3

million megawatt days of capacity annually– For 2007, forecast capacity price of $40/MW day– For 2008, expect capacity price range to be $50/MW day to $100/MW day

36%66%90%Percentage of capacity hedged (PJM & NY)200920082007

You’ll note that our 2008 guidance range is 50 cents wide. One notable area of uncertainty is capacity market reform in PJM. Capacity markets have been enhanced significantly over the last several years. With the FERC’s recent order in December to the PJM ISO to implement the RPM construct, we expect that higher capacity revenues may add to the revenue from our generation plants in PJM.

Given the growing importance of capacity as a revenue source, we will provide information on our capacity position with a similar level of transparency to what we have provided relative to our energy position over the last several years. As with energy, we have sold capacity to many load serving customers and bought capacity from numerous generators over the last several years. Given competitive dynamics, we can not provide the details of our positions in every location, but – as we have done with energy – we want to help you understand our net capacity position and potential variability on the open amount.

Our total fleet in PJM and New York produces about 3 million MW Days of capacity annually. Over the next three years our hedge ratios on this capacity position are 90% in 2007, 66% in 2008 and 36% in 2009.

As to capacity pricing, we have forecasted the value of our open capacity position at prevailing forward market prices, just as we have done over the last several years for energy. The forward price we assumed for our open position in 2007 is $40/MW Day. For 2008, capacity markets are still somewhat illiquid, but our best guidance is that it could range between $50/ MW day and $100 per MW day.


52

52

Long-term Earnings Outlook

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

2.89

3.61

5.25 - 5.75

4.30 - 4.65

$2.50

$3.50

$4.50

$5.50

$6.50

2005 2006 2007E 2008E

• Business outlook for Constellation remains robust• Reaffirming guidance for 2007 and 2008• 2009 adjusted EPS growth of approximately 10% over 2008

Adj

uste

d EP

S (1

)

($ per share)

Compound Annual Earnings Growth of 22% - 26%

Taking 2007 and 2008 together, we expect earnings growth of 22% to 26% per year from 2005 to 2008.

Several of you have asked if we’ll provide a point estimate for 2009 EPS. As you'll recall, two years ago we provided you with an EPS guidance range over a forward three-year period. With the substantial earnings increase driven by the roll-off of below market hedges, we felt it was important to communicate our embedded growth by extending our guidance horizon to three years. Now that this phenomenon is understood, we think a sounder practice is to focus more generally on long-term growth rates.

Looking beyond 2008, our best guidance to you is 2009 EPS growth of about 10% over 2008. In Tom’s section, we provided our estimate of fleet EBITDA growing from $1.27 billion in 2008 to $1.44 billion in 2009. This alone is about 45 cents per share or 8 percentage points of EPS growth. For 2009, we are hedged 79% on the power side and 56% on the fuel side and so have greater exposure to changing commodity prices than in 2007 and 2008. On the other hand, modest growth expectations for competitive supply make all-in EPS growth of 10% seem very reasonable.


53

53

Solid Base of Growing Earnings

Note: 2004 – 2006 includes gas-fired merchant plants, except High Desert

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2004 2005 2006 2007E 2008E

EBIT

DA (

$ bi

llion

s)

Utility Generation Retail Businesses Commodities - Backlog at 12/31 Commodities - New Business

BGE

Generation Fleet

Retail Businesses

Commodities Backlog at 12/31

Commodities New Business

• Earnings from low-risk sources represent 87% of 2007 EBITDA and 82% of 2008 EBITDA– Base of utility earnings– Highly hedged generation output– Retail businesses (NewEnergy) with high customer retention rates– Strong Commodities backlog of already-originated transactions

Our growth rates will be very high over the next three years, and we have tremendous visibility on the earnings growth drivers. The dark blue on the bottom reflects the solid base of utility earnings from BGE. The royal blue section above BGE represents EBITDA from our generation fleet, which is now moderately hedged and balanced as to commodity price exposure through 2009. Fleet EBITDA will grow from 32% of Constellation’s total 2006 EBITDA to 48% in 2008. The area above the generation fleet is NewEnergy. For 2007, over 65% of NewEnergy’s projected gross margin is already contracted. NewEnergy has high customer retention rates, that is, a good track record of retaining customers whose contracts expire, which bodes well for winning new business. The light blue segment shows the strong commodities group backlog of already-originated transactions to be realized in future earnings. Approximately 45% of the projected 2007 Wholesale Competitive Supply gross margin is already contracted. Adding it together, earnings streams with high visibility, represented by blue here, are 87% of 2007 EBITDA and 82% of 2008 EBITDA.

54

54

Agenda





Now let me turn to capital spending, cash flow and the balance sheet on slide 55…

55

55

Capital Spending

(375)(583)194Change

1,3311,3341,343Prior Plan

150152137Nuclear Fuel

$ 686 $ 565$ 252Generation Plants

433442360Utility Total

$ 1,266$ 1,465$ 768Merchant Total

71021Other Non-regulated Business Total

174197152Technology & Other

$1,706$1,917$1,149Total Capital Expenditures

256551227Commodities Group Portfolio

Transactions & Gas Invest.

Merchant

2008E2007E2006($ in millions)

• Key drivers of capital expenditures:– Additional costs for environmental compliance– BGE system load and infrastructure requirements– Upstream gas and portfolio investments to fuel growth

This chart represents the capital spending projections in our business plan. As you recall, we give you a capital spending forecast that includes only known or reasonably likely investments. We don’t include unknown M&A, for instance, so accordingly, what you have is essentially an organic business plan.

Our current plan is to spend $1.9 billion in 2007 and $1.7 billion in 2008. Increases in our capital forecast are driven by environmental capital spending related to Maryland Healthy Air Act, higher merchant capex driven by increased investment in our successful upstream gas business, and utility spending driven by the need to add transmission capacity to bring power into the region and replacing and upgrading substation equipment liketransformers and switches and running new feeders to accommodate growth in the City of Baltimore.

Turning to page 56…

56

56

Environmental Capex

7405814231019040Prior Projections (1/06)

$1,143$63$267$466$329$17Current Estimate

23

2006

(139) (403)(5)(125)(156)Change

2007 Total2010+20092008($ in millions)

Note: Excludes capitalized interest

• Environmental spending increase driven by– Finalization of Maryland Healthy Air Act increased project requirements– Increased labor and materials cost due to higher construction demand

This chart shows you the breakout of our projected environmental capex 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. Last January, we projected environmental spending of $740 million through 2010. Maryland’s Healthy Air Act was finalized in 2006, and the Clean Power Rule was finalized in early 2007. Maryland’s rules, which exceed Federal standards, have required that we add additional equipment, resulting in cost increases. In addition, like many companies, our costs also have gone up as market labor and material costs are increasing. We currently expect spending of $1.1 billion over the 2007 to 2010 period.


57

57

Capital Investments Fuel Future GrowthImpact on Future GrowthCapital

• Transmission interests on formula rates• 2008 Rate Case providing returns starting in 2009

on distribution capital• AMI/DRI initiatives represent potential upsides

if supported by regulators

BGE

• Transmission

• Distribution

• AMI/DRI

• Placeholder for upstream gas investments in 2007• Earnings on gas investments modeled as if CEG

holds investments for entire productive cycle but actually expect to harvest investments as proven reserve levels rise

Upstream Gas Investments

• Upward pressure on capacity prices in Southeast PJM could provide offsetting revenuesEnvironmental Spending

With each category of upcoming investments, we see a clear linkage to future earnings benefits. With our environmental spending, we expect to see offsetting capacity revenue as investments by ourselves and others put upward pressure on capacity prices in Southeast PJM. We’ve currently modeled the impact conservatively in our forecast. As the implementation becomes more clear, we will better understand the full impact to our growth.

In upstream gas, we are pleased with success to date in the business and we have a place holder for investments in 2007 of about $225 million higher than 2006. We modeled the earnings on the upstream gas business conservatively, assuming we hold each investment for its entire life cycle. However, we actually expect to harvest investments as proven reserve levels begin to rise, which should lower the net investment in this business. And this business of course is different from launching a project like the Brandon Scrubber where we will have committed to and launched a sizeable program. With the gas business, each discrete investment is much smaller, we evaluate each one carefully, and if lucrative opportunities do not present themselves, we will not spend the capital.

Finally, our investments in utility reliability and infrastructure will yield future benefits. Our 2007 BGE capital program will be up $80 million over 2006 levels. $50 million of this is in transmission projects which are subject to formula rates which allow us to start earning that return when the capital is spent. The remainder is traditional electric distribution spending to increase reliability of the sort never challenged in any jurisdiction in the U.S. This spending supports construction for increased load growth in the area and also supports the replacement of aging infrastructure to increase reliability. As I mentioned, we have assumed that we will file an electric distribution rate case no later than 2008 and that BGE will start to see returns on this capital in 2009. Not included in our projects are initiatives we are evaluating in advanced metering and demand response which we would undertake if Maryland regulators are supportive. These are initiatives which we think are the right thing to do and which would provide a fair return to shareholders. We’ll tell you more about these if Maryland is supportive. All these investment opportunities, environmental spend in PJM, BGE T&D spending and new gas provide a foundation for meaningful earnings growth after the 2007 / 2008 period.


58

58

2007E and 2008E Consolidated Cash Flow

See Appendix

(82)(70)--(70)Asset Disposition & Contract Restructuring

100(19)---Pension Adjustment (pre-tax)

(125)(194)25(50)(169)Working Capital & Other

$13($700)$40($123)($598)“Operating” Cash Flow

($1,339)

(306)

(29)

($1,004)

(234)

($1,309)

(1,874)

565

$822

2007 Total

54-(234)-SB1 Rate Deferral

(24)Equity – Benefits Plans

7199237319Depreciation & Amortization

$996$13$130$679Net Income

($391)Net Cash Flow before Debt Issuances/(Payments)

(352)Dividends

($15)$40($357)($668)Free Cash Flow

($958)$2($203)($1,108)Net CapEx

(1,677)(7)(440)(1,427)Capital Expenditures / Investments

2008 TotalOther

Non-RegUtilityMerchant($ in millions)

• Merchant business growth, environmental investments, and rate stabilization is expected to result in the use of $1,339 million in cash during 2007

Bringing the capital and earnings picture together, as you can see on the “operating” cash flow line in the middle of the chart, in 2007, we expect operating cash flows to be a use of $700 million. Additionally we will see a use of $234 million related to the continuation of the Senate Bill-1 rate stabilization plan deferrals for our BGE utility, which will be funded by securitization later this year.

After dividends our cash flow will be about $1.3 billion negative – reflecting our investment in the business combined with the payment of about $300 million in dividends.

In 2008, with earnings growth and moderating net capital spending, operating cash flow is neutral. With dividends, free cash flow is negative. By 2009, the environmental capital compliance program at Brandon is nearing completion, earnings are up, and we expect free cash flow to be positive.


59

59

2007E Balance Sheet / Credit Metrics

1) 2007 and 2008 Total Debt excludes BGE securitization assumption(2) Includes preferred stock and minority interest(3) Excludes AOCI balance related to cash flow hedges of commodity transactions and 3rd Party Cash CollateralSee Appendix

--0.30.4-3rd Party Cash Collateral

1.11.31.40.3-AOCI Balance

39% - 43%40% - 44%35%43%55%Net Debt to Total Capital

25% - 28%

35% - 39%

$8.7

5.1

$0.1

$3.5

(0.8)

$4.3

YE 2007E

36% - 40%32%44%55%Adjusted Net Debt to Adjusted Total Capital(3)

$0.1$0.1$0.1$0.150% Trust Preferred

Capital

$3.9$2.7$3.9$5.1Net Debt

5.74.95.14.1Equity (2)

(0.4)(2.3)(0.8)(0.1)Less: Cash

$9.7$7.7$9.1$9.4Total Capital

$4.3$5.0$4.7$5.2 Total Debt(1)

26% - 29%16%29%19%FFO / Debt

Debt

YE 2008EYE 2006YE 2005YE 2001($ in billions)

Net debt-to-total capital at the end of 2006 was 35%, significantly lower than our 2005 year-end ratio of 43%. The key driver behind this decrease was the receipt of cash proceeds generated from the sale of six gas fired plant assets in December 2006 for $1.6 billion proceeds.

As we mentioned before, these proceeds will be used to repay approximately $700 million of debt that will be maturing in early 2007. Additionally, the strong cash balance provides us the liquidity to fund our 2007 capital plan.

Net debt to capital will rise in 2007 and 2008 as we execute our capital program and pay healthy dividends, assumed in our projections to grow by 15% per year. We've mentioned in the past that the 40% net debt to total capital target was a proxy for a number of credit metrics we and the rating agencies monitor. Those of you who focused on S&P's upgrade of CEG's debt to BBB+ will have noted a target funds from operations to debt ratio between 25 - 30% to sustain the current rating. FFO, of course, includes net income plus D&A, deferred taxes and other non-cash items. S&P also imputes debt for structured contracts and capital leases. In 2007, we will be in the lower half of the 25 - 30% range and debt to capital will be in the targeted 40% area. Accordingly, we have achieved our balance sheet objectives and will be able to maintain this strong position over the next three years.

60

60

Agenda





Now, turning to slide 61, let me reflect on the sources of growth at Constellation and the implications for our valuation…

61

61

CEG Growth Drivers: Executing on Multiple Fronts2002 - 2006 2007 - 2009 Next Decade

Competitive Supply

Taking Load Serving / Structured Commodity Transaction Market Share

Building Gas Business

CNE Cost Structure Leverage

Opportunities to Leverage Wholesale / Retail Load Serving

Generation

Opportunities to Leverage Wholesale / Generation Interface

Productivity New Nuclear

Upward Pressure on Capacity Prices

Impact of Rising Commodity Prices on Baseload Fleet

BGE Return on T&D/Conservation Initiatives

For the 7 year period from 2002 to 2009, we expect to grow adjusted EPS at 13% per year, that’s a level rarely seen for such a sustained period in the business world. We’ll have achieved this by executing on multiple fronts across each area of the business.

In competitive supply, we have been and will continue to take market share in load serving and structured commodity transactions and to take market share in the gas business by providing capital and services to customers who are somewhat underserved. We expect to benefit from continued focus on leveraging the cost structure at NewEnergy. As we realign our merchant segment, we expect opportunities to leverage the infrastructure and processes across the wholesale and retail load serving businesses to further grow earnings.

Our Generation activities will present opportunities to leverage the wholesale commodities, and generation interface. We have seen and expect to see benefits from generation productivity initiatives. The impact of rising commodity prices will benefit our earnings growth over the next several years as we experience the roll-off of earlier vintage hedges and realize higher market prices. Later in the decade, we project earnings growth will be driven by upward pressure on PJM capacity prices due to environmental capital investments that plant owners are making over the next several years. Finally, we are evaluating the viability of building new nuclear plants which would manifest returns in the next decade.

At BGE, we are making investments now to improve the infrastructure of the utility. We are also exploring upside opportunities for investments to support energy conservation, which is the right thing to do and would provide returns to our shareholders.

Together, we have a healthy array of sound growth initiatives to be executed by a management team with a proven track record.


62

62

Mapping Management Reporting to Valuation Framework

Valuation FrameworkManagement Reporting Structure

QFs / Other

Mid-Atlantic Fleet

Plants with PPAs

New Energy

Wholesale Competitive Supply

Generation

Load Serving

Risk Management & InvestingPower Load Serving

We realize that because of the sources of our growth we are meaningfully different from others in the industry. We speak to many of you directly, on a regular basis, and recently concluded an investor perception study. One of the consistent themes we hear from you is a desire for us to provide our thoughts on how to value the merchant.

Now, while I realize that providing valuation thoughts is somewhat unconventional, quite literally you asked for it.

We’ve grouped our merchants earnings into the three business activities Tom used: Generation, Load Serving, and Risk Management and Investing.

Load serving comprises NewEnergy, which serves retail gas and electric load, and Wholesale load Serving. The remaining businesses in Wholesale Competitive Supply, including our portfolio management and trading operations, the upstream gas and coal logistics businesses, are grouped into Risk Management and Investing.

Moving to slide 63...

63

63

Thoughts on Merchant Valuation

• Use unhedged EBITDA

• Compare to unhedged EBITDA multiples of merchant generators

• Subtract after-tax NPV of hedges

• Value drivers of specialty insurers provide good comparison

– Provide risk mgmt service for complete liability exposures for which "commoditized" loss experience data is not available

– Profit margins adequate to provide good RAROC

– Hedge internal risk– Engage in extensive portfolio

management and optimization– Discipline to shrink share when

competitive pricing is overly aggressive important to long-term success

– Human capital and systems intensive

• Value drivers of energy-focused hedge funds and merchant banks provide similar comparison

– Trade proprietary positions across broad array of markets and commodities

– Engage in extensive portfolio management and optimization

– Human capital intensive business

– Highly complex products, systems and services to minimize risk

– Hedge internal risk

Generation Load Serving Risk Management & Investing

For Generation we think the EBITDA multiples of other merchant generators make a good comparable. However, because different merchants began the practice of hedging output at different points in history, we think it is necessary to determine the relevant multiple applied to the unhedged EBITDA of our comparables’ output. For each Merchant Genco comparable, we made an estimate of the after-tax net present value in or out of the moneyness of their hedges. We subtracted that from their enterprise value to arrive at an unhedged enterprise value. Separately, we estimated EBITDA from their output at today’s market prices. We divided this unhedged EBITDA into the adjusted enterprise value to arrive at unhedged EBITDA multiple. We apply that multiple to our unhedged EBITDA, and then we subtract the after-tax NPV of the hedge contracts from that value.

For the load serving business, there are no publicly-traded comparables. So what we tried to do is to think about businesses which provide conceptually similar services and which have similar value drivers as the load-serving business. We think specialty insurance is a good analogy. In load-serving, as in specialty insurance, we absorb risks which are not yet commoditized from a loss experience data perspective. We step in between buyers and sellers of energy to accept and manage their risks with a profit margin adequate to provide an attractive return on the capital we put at risk. Risk management expertise, portfolio management and optimization are key success factors in our business as in the insurance business. The discipline to throttle back on growth rather than assume inappropriate levels of risk when competitors are driving deal pricing to unsustainable levels is important in our business as to good insurers. And we are a human capital and systems intensive business.

Lastly, in choosing comparables for our Risk Management & Investing, we concluded that many types of businesses perform portfolio management functions but that merchant banks are most closely aligned to our portfolio management and trading operations. In the Risk Management and Investing business, just as a merchant bank does, we provide extensive portfolio management activities to optimize the return on the portfolio, we trade proprietary positions, our infrastructure is powerful human capital and complex systems, and we actively hedge our internal risks. This grouping of business activities also includes the gas and coal services business, but we haven’t attempted a separate valuation metric given their relatively smaller size.


64

64

Sum-of-the-Parts Valuation

1,100Merchant Net Debt

Utility

Merchant

13 – 17130Net IncomeBaltimore Gas & Electric

EBITDA

EBITDA

EBITDA

Earnings Metric

5 – 7 (3)342Risk Management & Investing

7 – 9 (2)402Load Serving

(2,200)NPV of Hedges (after-tax)$1,922

2007 Forecast($ in millions)

7x – 10x (1)

Comparable Multiple Range

Unhedged Generation Fleet

(1) Unhedged EBITDA multiple range for comparable merchant generators(2) EBITDA multiple range for specialty insurers(3) EBITDA multiple range for merchant banksSee Appendix

Page 64 details the components of a sum-of-the parts valuation using the referenced comparables. If you want to look at this analysis further, you will find a list of the comparables we used in the appendix we’ve provided. I’ll note that also in the perception study, a number of you teased that we are “sandbaggers” in providing earnings projections. We truly develop projections that we will expect to meet or beat, not just consistently beat. Of course, if you believe our projections are conservative, that would imply application of the upward-end of valuation metrics. I will leave it to you to do that math and to evaluate the validity of this valuation approach. I think that you’ll conclude that even at the low end of each of the indicated valuation ranges, an investment in Constellation appears to offer significant opportunity.

On that note, I’ll turn the podium back over to Mayo.

65

Constellation Energy2007 Analyst Presentation

Mayo ShattuckChairman, President & Chief Executive Officer

Great. Thanks, Follin.

66

66

Poised to Succeed in 2007 and Beyond

• Clear and substantial earnings growth over next five years– Projecting 22% to 26% compound annual earnings growth from

2005 through 2008

• Constellation has outperformed over the past five years through a variety of market conditions– Delivered annual total shareholder return of 28% per annum since

management team came together in late 2001

• Our strong market position will enable us to take advantage of developing market opportunities

So, throughout the morning, you’ve heard me, Tom and Follin describe the outlook for Constellation. So, let me quickly restate our key themes. First, our earnings will grow substantially over the next three years, based on clear drivers, primarily the return of the Mid-Atlantic Fleet to profitability as below-market hedges roll off. We are projecting 22% to 26% compound annual earnings growth from 2005 through 2008.

Second, this management team has been a very effective steward of your capital. As you look back over the past five years, our stock price has outperformed through a variety of market conditions. We have delivered total shareholder return of 28% per annum since this management team came together in late 2001.

Third, as we look to the future, we feel that we are just getting started. Today, we have a solid foundation built on a well-managed, high-quality asset base, market-leading customer franchises and a strong balance sheet. So, today’s starting point is far better that where we were five years ago. We believe the market environment is very attractive and that our team is well-positioned to capture the opportunity.

That concludes our prepared remarks.

I’ll point out that we brought our entire senior management team with us today, and I will serve as a moderator for any questions and all of the management team are perfectly willing to dive into this.

So, I know it’s a long presentation with lots of information, but we’re happy to clarify or answer anything you might have.

67

Additional Modeling

68

68

Additional Modeling

• CEG Financial Results

– Reconciliation from GAAP to Adjusted EPS p. 69 - 70

– FAS 158 Impact p. 71

• CEG Financial Outlook

• Commodities

• NewEnergy

• Generation

• BGE

69

69

Full Year Reconciliation from GAAP to Adjusted EPS

2006

$3.61

(0.16)

(0.21)

(1.04)

(0.14)

$5.16

$2.89

(0.33)

0.14

(0.53)

0.14

$3.47

20052004($ per share)

-Non-Qualifying Hedges

(0.29)Synfuel Earnings

$2.43Adjusted EPS

(0.24)Discontinued Operations

(0.16)Special Items

$3.12GAAP EPS

See Appendix

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 it 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 2006, GAAP earnings were $5.16 per share. Let me walk you through the adjustments to arrive at management EPS. In the chart you see $1.18 per share of special items in 2006: High Desert operating earnings and the gain on sale, together $1.04 per share, must be reclassified to discontinued operations under FAS144. The gain on sale of the other plants is a 26 cent special item to be called out of GAAP EPS. We have 9 cents of workforce reduction costs at our nuclear plants and 3 cents of merger-related costs. We are subtracting from GAAP EPS a gain of 21 cents on non-qualifying hedges and earnings of 16 cents on our synfuel plants to arrive at management EPS of $3.61. This adjusted EPS of $3.61 is 16 cents higher than our updated EPS guidance of $3.30 to $3.45 that we gave you at the end of the third quarter. And 31 cents higher than guidance provided at the beginning of the year.

70

70

Quarterly Reconciliation from GAAP to Adjusted EPS

$0.87$0.98$0.50$0.54Adjusted EPS

(0.10)(0.08)(0.09)(0.07)Synfuel Earnings

(0.06)0.130.020.04Non-Qualifying Hedges

(0.19)(0.11)(0.11)(0.11)Discontinued Operations

0.130.01--Special Items

$1.09$1.03$0.68$0.68GAAP EPS

Q4Q3Q2Q1

2005

2006

$1.08

(0.04)

(0.07)

(0.76)

(0.27)

$2.22

Q4Q3Q2Q1($ per share)

(0.20)-0.06Non-Qualifying Hedges

(0.11)0.01(0.02)Synfuel Earnings

$1.46$0.45$0.61Adjusted EPS

(0.10)(0.11)(0.07)Discontinued Operations

0.080.030.01Special Items

$1.79$0.52$0.63GAAP EPS

See Appendix

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 2005 and 2006.

Fourth quarter GAAP earnings were $2.22 per share. We recognized several special items most notably the gain on the sale of the gas fired plants and the reclassification of the High Desert plant’s earnings to discontinued operations. After special items, our fourth quarter management EPS was $1.08 versus a guidance range of $0.75 to $0.90 per share.

71

71

Impact of SFAS No. 158 Implementation• Effective December 31, 2006, SFAS No. 158 requires full recognition of defined benefit plan funded status on balance sheet

(i.e., the difference between plan assets and benefit obligation)– Pension Plans – Unfunded Accumulated Benefit Obligation (ABO) is already recognized on the balance sheet through the Minimum

Pension Liability. Under SFAS No. 158, the difference between the ABO and the Projected Benefit Obligation (PBO) will be recognized on the balance sheet

– Post-retirement Benefit Plans – Funded status will be recognized on balance sheet

$95$60$35Impact on Equity at 12/31/06

$170$60$110After-tax AOCI Charge (Credit)

$281$100$181Incremental Liability to be Recognized630342(2)288Less: Liability per Books911442469Unfunded Liability442$442Accumulated Post-retirement Benefit Obligation (APBO)

1,6301,630Pension Projected Benefit Obligation (PBO)$1,161$1,161Fair Value of Pension Assets

SFAS No. 158 Implementation at 12/31/06

($75)($75)After-tax AOCI Charge (Credit)$316$316Unfunded Liability1,4771,477Accumulated Benefit Obligation (ABO)

$1,161$1,161Fair Value of Plan AssetsSFAS No. 87 Pension Plan Minimum Liability (1)

TotalPost-retirement

BenefitsPension Plan($ in millions)

(1) SFAS No. 158 requires the computation of SFAS No. 87 Pension Plan Minimum Pension Liability at 12/31/06 prior to the implementation of SFAS No. 158(2) Unfunded ABO of $316 million, net of SFAS No. 87 Intangible Asset of $28 million

In 2006, FASB issued SFAS No. 158, which became effective on December 31st, 2006. The most significant impact is the requirement for balance sheet recognition of the funded status of defined benefit plans in lieu of previous footnote disclosures. In Constellation’s third quarter 2006 Form 10-Q, we disclosed that we expected to record an after-tax charge to equity of approximately $90 million upon the adoption of SFAS No. 158. The actual impact is $95 million. Absent the implementation of FAS No. 158, we would have recognized a $75 million after-tax credit to AOCI/equity under the FAS No. 87 Additional Minimum Pension Liability adjustment reflecting 2006 favorable asset returns and an increased discount rate. This was more than offset by FAS No. 158’s requirement to measure pension underfundedness using the higher PBO measure, which takes future salary increases in account and now having to reflect post-retirement benefit (PRB) underfundedness.

72

72

Additional Modeling• CEG Financial Results

• CEG Financial Outlook

– Earnings Analysis p. 73 - 81

– Cash Flow & Liquidity p. 82 - 85

– Synfuels p. 86 - 88

– Gas Plant Sale Facts p. 89

– Commodity Price Sensitivity p. 90

– Valuation Comparables p. 91

• Commodities

• NewEnergy

• Generation

• BGE

73

73

2006 to 2007 Earnings Walk

(1) Excludes special items, certain economic, non-qualifying hedges and synfuel earningsNote: Analysis assumes midpoint of 2007 guidance rangeSee Appendix

($ per share)

(1) $3 .61

2007$4.30 - $4 .65

( 0 .19) BGE

(0 .17)

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

$4.75

Generation

OtherProductivity &

Inflation

Earnings Drivers• Generation - Mid-Atlantic Fleet returning to profitability as below-market hedges roll off and fewer planned nuclear outage days in 2007

partially offset by end of competitive transition charge• Competitive Supply

− Wholesale down due to lower PM&T and moderating power market conditions offset by strong backlog and gas new business growth− NewEnergy up primarily due to higher gas volumes

• Net Productivity - Continued productivity gains at generation and staff partially offset by inflation• BGE – Loss of decommissioning revenue and residential POLR margin and other costs partially offset by return to normal weather

This chart walks you through the factors that will contribute to our 2007 earnings growth.

Generation profits will grow by 92 cents in 2007 driven primarily by the 83 cents per share affect of the improvement in fleet price and the 20 cent impact of fewer planned nuclear outage days in 2007. These positives will be partially offset by the negative 14 cent impact of the end of the competitive transition charge.

Our competitive supply businesses are forecast to be down 19 cents in 2007, with a decrease in wholesale profits to be partially offset by an increase in NewEnergy's profits. First, we’re forecasting a significant decrease in wholesale portfolio management and trading which had a banner year in 2006. Second, in wholesale power, a monetized contract added to profits in 2006 and, in general, we saw very robust new business conditions in wholesale power. Accordingly, we are assuming 2007 power results will be down with the assumption of a more normalized environment. On the other hand, wholesale backlog is $150 million higher going into 2007 than it was in 2006, and we expect to see good new business growth in gas. With respect to retail, EBIT will be up as the gas business projects an increase of about 1 percentage point in market share, with about 74% of planned volumes already contracted. The retail electric business picks up volume in markets transitioning at the beginning of 2007, namely IL, CT and PA. Sixty-six percent of electric plan volume is already contracted, slightly ahead of where we were this time last year. The profit impact of the electric volume pick up will be offset by an assumption that we trend back to normalized unit margins after a very favorable 2006 environment.

Continued productivity gains of 22 cents in 2007 will be partially offset by 8 cents of inflationary cost increases, resulting in a net earnings increase of 14 cents.

BGE’s earnings will be down 17 cents. The main drivers are associated with last year’s Maryland legislative actions, which in aggregate cost us 9 cents, and 15 cents for an accumulation of smaller items. These negatives will be partially offset by a favorable 7 cents due to our forecast assumption of a return to normal weather.

In other, the primary drivers are lower interest expense partially offset by the absence of gas plant earnings excluding High Desert.

74

74

Substantial Backlog and Consistent Renewals Create Earnings Visibility

• 2007 competitive supply contribution margin forecast slightly below 2006 exceptional performance• Strong contracted backlog and high retail renewal rates account for approximately 52% of 2007

competitive supply gross margin• Future backlog creates earnings visibility for future years

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2006A 2007 2008 2009

Con

trib

uti

on M

argi

n (

$ in

mill

ion

s)

Contribution Margin Backlog as of 12/06CNE Contract Renewals New Business

$1,392

4%

46%

$1,303 $1,379

$1,520

$674

$69

$560

$351

$239

$789

$301

$256

$963

See Appendix

You’ve heard us say before that we have good visibility into our future earnings due to our backlog. Let me remind you briefly what we mean by backlog. Backlog includes scheduled realization for power transactions and reasonable expectations for gas production.

This chart outlines our combined wholesale and retail competitive supply contribution margin target through 2009 and the percentage of the contribution margin already booked in backlog as of the end of 2006. In dark blue you see the backlog of contribution margin that the competitive supply team, including wholesale and retail, has already contracted for future years. For 2007, we have $674 million of gross margin in backlog, or about 52 percent of the full-year target year for the competitive supply group. More specifically, wholesale backlog is currently at $369 million which is 44% of their 2007 target of $837M, which compares favorably to wholesale backlog of $300 million, or 40%, booked this same time last year. Retail backlog currently consists of $306 million of contracted gross margin and an additional $69 million of gross margin from renewals at historical renewal rates, which total represents 80% of their 2007 full year target of $466 million.

You can see that each year going forward we’ve already got a good start on the target. Throughout the year, as we contract new business, you should expect to see the target in the out years decrease as we contract future years gross margin.

This ability to consistently generate backlog is what provides us with substantial visibility into future earnings.

75

75

Merchant – Income Statement – Q4 2006

28%2911Qualifying Facilities / Other

(8%)(11)135124Plants with PPAs

20%39196235Mid-Atlantic Fleet

49%4591136NewEnergy

(4%)($13)$285$272Wholesale Competitive Supply

(5%)3(62)(59)D & A (3)

42%$48$113$161Net Income

68%(42)(62)(104)Income Tax

51%$90$174$264Pre-Tax Income

(7%)2(36)(33)Net Interest Expense

42%$87$210$297EBIT

(5%)25(507)(482)Total Costs below Gross Margin

(0)

22

62

$

Change

0%

(5%)

9%

%

(35)(35)Other Revenue and Expenses

(410)(388)O & M

717779Gross Margin (2)

Q4 2005 A(1)Q4 2006 A(1)($ in millions)

See Appendix

(1) Earnings excluding special items, certain economic, non-qualifying hedges, and synfuel earnings(2) Includes $33M and $35M of nuclear fuel amortization for Q4’05 and Q4’06, respectively(3) Includes $2M and $5M of depreciation, amortization and depletion from wholesale gas business for Q4’05 and Q4’06, respectively

This chart shows the actual results on the Merchant income statement for 4Q 2006 versus 4Q 2005.

Wholesale Competitive Supply gross margin was down $13 million, or 4%, in 4Q 2006 versus 4Q 2005 driven by very strong trading results in 4Q 2005 offset by higher backlog in 4Q 2006.

NewEnergy increased $45 million in 4Q 2006, or 49% over the same period in the prior year driven by favorable rates in electric of $53 million offset by an unfavorable $8 million in gas mark to market losses.

With the return of the Mid-Atlantic Fleet to profitability as below-market hedges began to roll off, 4Q 2006 gross margin was up $39 million, or 20%, over 4Q 2005 due to favorable prices offset by loss of CTC revenue, lower volume and gross margin productivity.

Plants with PPAs were down $11 million, or 8%, for 4Q 2006 as compared to 4Q 2005 due to lower prices.

Overall, merchant gross margin increased $62 million, or 9%, for 4Q 2006 over 4Q 2005.

76

76

Merchant – Income Statement

9%(4)5349Qualifying Facilities / Other

8%46574620Plants with PPAs

33%2567861,042Mid-Atlantic Fleet

13%54411465NewEnergy

(11%)($116)$1,040$924Wholesale Competitive Supply

6%(15)(257)(273)D & A (4)

40%$194$485$680Net Income

37%(117)(318)(435)Income Tax

39%$312$803$1,115Pre-Tax Income

(54%)91(169)(77)Net Interest Expense

23%$220$972$1,192EBIT

1%(16)(1,891)(1,907)Total Costs below Gross Margin

(34)

34

236

$

Change

24%

(2%)

8%

%

(143)(177)Other Revenue and Expenses

(1,491)(1,458)O & M

2,8643,100Gross Margin (3)

2006(2)2007E(1)($ in millions)

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 $127M and $146M of nuclear fuel amortization for ’06 and ’07, respectively(4) Includes $20M and $40M of depreciation, amortization and depletion from wholesale gas business for ’06 and ’07, respectively

In 2007, we project Wholesale Competitive Supply gross margin to be down $116 million, or 11%, compared to an exceptional performance in 2006. We are forecasting healthy growth in wholesale gas and coal, supported by good backlogs. Wholesale power is forecast to have profits relatively unchanged from 2006 levels. We believe it prudent to forecast moderating wholesale portfolio management and trading results for 2007 given the very strong results of 2006.

NewEnergy is projected to be up for the year, improving gross margin levels by $54 million, or 13 percent, driven by strong switched market growth leading to higher volumes.

The Mid-Atlantic Fleet gross margin is expected to increase by $256 million in 2007, a 33% increase, driven by the return of the fleet to profitability as a significant portion of our revenues had been hedged in 2001 in conjunction with Maryland deregulation, while fuel costs were not locked in. Let me give you some background on what we have labeled “Mid-Atlantic Fleet” here. We know you want to understand how much we make from selling the output of the Mid-Atlantic fleet. As you recall, the commodities group manages the output of the Mid-Atlantic plants along with all other PJM competitive supply activity in one regional portfolio, in order to optimize the value. That’s part of the strength of our integrated business model. Here we have taken our PJM regional portfolio gross margin, subtracted out notable competitive supply deals not off the fleet to approximate the Mid-Atlantic fleet’s gross margin.

We expect Plants with PPA’s to be up $46 million, or 8 percent. Outages are roughly half of this, primarily due to the Ginna not having refueling downtime and the smaller Nine Mile unit in outage in ’07. The remainder of the ’07 upside is due the impact of the ’06 uprate at Ginna on ’07 megawatt hour production.

In the aggregate, we expect merchant gross margin of roughly $3.1 billion, up nearly $236 million, or about 8% from 2006.

77

77

Connecting the Dots

($273)2007 D&A (1)

(15)Change

(13)(11)

GenerationOther

29Generation - Sale of Gas Plants(20)Upstream Gas Depletion/Depreciation

($257)2006 D&A

($1,458)2007 O&M (1)

34Change10Other28Generation – Sale of Gas Plants

940

(25)

Upstream Gas O&MGeneration & HQ ProductivityInflation

(15)NewEnergy Cost to Drive Growth(13)Commodities Cost to Drive Growth

($1,491)2006 O&M

(1) Represents mid-point of the guidance rangeSee Appendix

Year-over-year, O&M expenses are projected to decrease by $34 million. Commodities and NewEnergy will add about $28 million to their cost base to drive top-line growth. Increases in O&M expenses to grow the business will be more than offset by the reductions in O&M from the sale of the gas plants of $28 million and productivity savings of $40 million.

D&A will be up $15 million in 2007. Most notable is the forecast of gas depletion which reflects amortization of our gas investments with production offset primarily by the absence of depreciation associated with the gas plant sale.

78

78

Merchant Margin Statistics

66%Approx. Generation Group Op. Ex. as a % of Gross Margin (2)

Generation Fleet (1), (3)

44%Approximate Operating Expenses as a % of Gross Margin (2)

Wholesale Competitive Supply (1)

71%Approximate Operating Expenses as a % of Gross Margin (2)

NewEnergy (1)

2007E

(1) Includes allocation of corporate overhead(2) Operating expenses include depreciation and amortization(3) Includes Mid-Atlantic Fleet, Plants with PPA’s and QFs gross margin

For modeling purposes we want to provide you information on how to model the sub-components of the Merchant businesses, each of which includes allocation of corporate overhead. For NewEnergy we estimate their 2007 operating expenses will be approximately 71 percent of gross margin, including depreciation and amortization. For Wholesale Competitive Supply O&M is planned to be approximately 44 percent of gross margin (upstream gas is project margin), including depreciation and amortization. The generation fleet operating expenses are estimated to be about 66% of gross margin which includes depreciation and amortization for the Mid-Atlantic Fleet, Plants with PPA’s and QFs. This is a fairly sizable reduction in expenses as a percentage of gross margin from last years actual of 81%, driven by gross margin growth driven by the Mid-Atlantic Fleet returning to profitability as below market hedges begin to roll off.

79

79

Productivity Definition

Equals:

Less:

Plus:

Plus:

Less:

Productivity

(e.g. extraordinary maintenance)

Expense timing items that swing from year to year

Impact of D&A from spending on productivity initiatives

(e.g. higher MW, shorter base refueling outages)

EBIT increases driven by structural plant output increases

Increases due to general inflation and benefits inflation

Change in Generation and Headquarters O&M

• Decreases in existing plant cost and increases in existing plant output are productivity

This chart outlines how we track productivity. We apply a productivity definition akin to what many industrial companies use. This definition demands quantification of the all-in-change in cost relative to output. We break out inflation costs to help us better monitor productivity at Generation and Headquarters.

Expense timing items that swing from year-to-year and one-time items that could potentially distort productivity tracking, such as extraordinary fossil plant maintenance or replacement of reactor vessel head, are excluded from the calculation.

80

80

Productivity

38 - 41 Cost Productivity

28 Forecasted Inflation

$60 - $65Total 2007 Productivity

$852 2006842 - 8392007

10 - 13Change in Operating Expenses

22 - 24Gross Margin Productivity(1)

Generation and HQ Adjusted Operating Expenses

Favorable/ (Unfavorable)($ in millions)

• Constellation Energy EBIT $60 to $65 million higher in 2007 than 2006 due to productivity initiatives

• 2007 EBIT $157 to $162 million higher than 2003 due to productivity program

(1) 17% Ginna uprate (83 MW x 8,760 MWhrs/yr x 98.6% capacity factor x $40 gross margin/MWh)

Our total productivity target for 2007 is $60 to 65 million. These gains will largely be the result of already completed 2006 initiatives: we will have lower labor costs from a 2006 workforce realignment at Nine Mile Point, helping to drive $30 to $35 million in 2007 productivity; and the successful 2006 implementation of the 83 megawatt uprate at Ginna will drive another $19 million in 2007.

We have identified additional 2007 initiatives including work management and human performance initiatives that will further drive productivity results. We will also continue to benefit from our fleet management strategies as we leverage the best practices across the fleet to shorten outages and reduce costs associated with labor and materials.

In total, we expect 2007 EBIT to be $60 to 65 million higher than 2006 due to our continued focus on productivity initiatives. The cumulative impact of the productivity program will have raised the company’s EBIT by $157 to $162 million comparing 2007 to 2003, representing compound annual EPS growth of 2 percent.

81

81

2007 to 2008 EPS (Walk)

• The return of profitability of the Mid-Atlantic Fleet as below market hedges roll off will be the primary driver of growth for 2008

• The competitive supply businesses continue to build their backlogs and provide steady new business growth• Conservatively forecasting productivity

Growth Rate: 17% to 28%

($ per share)

See Appendix

2008 $5.25 - $5.75

2007 4.30 - 4.65

Other(0.03)

Mid-AtlanticFleet0.73

Competitive Supply

0.33 BGE

(0.07)

Generation Other(0.01)

Outages0.02 PPAs

0.05

$4.25

$4.45

$4.65

$4.85

$5.05

$5.25

$5.45

$5.65

$5.85

Generation

Let me focus on the growth drivers that support our guidance ranges.

The Generation area will contribute $0.79 of earnings growth. The biggest driver will be the earnings generated by the roll off of below market hedges in the Mid-Atlantic fleet. Revenue associated with our PPA’s will add 5 cents driven by favorable prices of 7 cents offset by higher costs of 2 cents.

We have projected earnings growth of 33 cents generated from Competitive Supply – both wholesale and retail. This projection is based on moderating new business growth assumptions on the wholesale side and modest market share gains and improving volumes on the retail side.

BGE will drive a 7 cent variance with the majority a result of interest and inflationary cost increases.

Finally, we’ve estimated a 3 cent increase in the aggregation of other charges due to the net impacts of interest which are slightly offset by dilution and offset by 5 cents of operating expense at the holding company to support the growth of the business.

82

82

2006 Consolidated Cash Flow

See Appendix

1,75019-1,731Asset Disposition & Contract Restructuring

33---Pension Adjustment (pre-tax)

($124)$30$297($484)Operating Cash Flow

$1,120

(264)

84

$1,300

(326)

(728)

($365)

(1,079)

714

$936

2006 Total

-(326)-SB1 Rate Deferral

Equity – Benefits Plans


$12$157$767Net Income

25217(970)Working Capital & Other

Net Cash Flow before Debt Issuances/(Payments)

Dividends

$49($29)$1,247Free Cash Flow

($7)($77)($281)Net CapEx

(16)(320)(743)Capital Expenditures / Investments

Other Non-RegUtilityMerchant($ in millions)

Last year, we said that we would end 2006 with approximately $148 million in free cash flow. We actually achieved $1.3 billion in free cash flow. This includes $900 million notable items not in plan: The $1.6 billion in proceeds from the gas plants sale; $225 million in proceeds from contract restructurings; a use of $326 million for the BGE rate stabilization plan; a use of $660 million of increased collateral requirements. The net effect is that our business generated about $300 million of free cash flow.

83

83

Cash Flow

(82)(70)1,750866Asset Dispositions & Contract Restructuring

13(700)(124)(305)Operating Cash Flow

100(19)3316Pension Adjustment (pre-tax)

54(234)(326)-SB1 Rate Deferrals

($391)($1,339)$1,120$429Net Cash Flow before Debt Issuance / (Payments)

(306)

(29)

($1,004)

(194)

($1,309)

(1,874)

565

$822

2007

(24)8497Equity – Benefits Plans


$996$936$625Net Income

(125)(728)(570)Working Capital & Other

(352)(264)(229)Dividends

($15)$1,300$561Free Cash Flow

($958)($365)($376)Net CapEx

(1,677)(1,079)(1,076)Capital Expenditures / Investments

200820062005($ in millions)

See Appendix

This slide shows the cash flow that the business is expected to use over the plan period.

We generated $1.3 billion of cash in 2006, largely as a result of the gas plant sales and contract restructuring.

In 2007 we expect to use $1.0 billion of free cash flow. Our cash flow usage is primarily driven by the $1.9 billion capital spending program. Additionally, we expect to use $234 million related to the continuation of the BGE rate deferral, and lastly we expect to see a use in working capital of $194 million aligned with the growth of our business, particularly our retail business. Our retail business is a natural user of working capital, our customer terms create a days sales outstanding (DSO) of about 43 days, while our supplier terms are shorter, so as our business grows so does the working capital to support the business.

As we look to 2008, our free cash flow begins to moderate to slight use of $15 million.

84

84

Significant Excess Liquidity

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

($ b

illio

ns)

Cash & Bank Lines Bank Line Usage

• Significant liquidity to support business growth• Sufficient liquidity to meet all stressed price and credit scenarios

(1) Excludes $2.5 billion bridge facility

31-Dec-01 (1) 31-Dec-02 31-Dec-03 31-Dec-04 31-Mar-05 30-Jun-05 30-Sep-05 31-Dec-05 31-Mar-06 30-Jun-06 30-Sep-06

Excess L

iquidity

Historical Excess Liquidity

31-Dec-06

This chart shows our excess liquidity, which was $5.5 billion at the end of 2006. The top line represents our cash balances plus our bank lines, the total of which was approximately $7 billion at the end of the year. The green line on the bottom of the chart shows our bank line usage as we post letters of credit with counterparties. At the end of 2006, we had posted about $1.6 billion in LCs. Our excess liquidity is at a temporary high point as of December 31, 2006. We have benefited from the $1.6 billion proceeds of the gas fired plant sale as well as the implementation of a $1 billion 364 day credit facility put in place upon the termination of the merger with FPL. Additionally in October, we executed $700 million of long-term debt to refinance upcoming debt maturities. As we go through 2007, we will utilize the excess liquidity to paydown about $700 million of debt maturities and to fund our capital spending program. We maintain cash reserves to manage the margin requirements inherent in our business. This chart illustrates Constellation’s continuous ability to access capital as our business has grown, maintaining a prudent liquidity position.

85

85

($321) ($151)($71)($250)($401)Cash Collateral Held

$258

(4)

67

6

61

Q4 QTD Change B / (W)

762 (416)701285Exchanges

(93)179185863rd Parties

(509)880947371Subtotal Posted

Collateral Posted

(660)630626(30)Net Cash Posted Subtotal

$249Change in Total Collateral Posted

$909$1,577$1,835$2,486Letters of Credit Posted

Change vs. Year-End B / (W)12/31/069/30/0612/31/05($ in millions)

Collateral Positions

• Net Liquidity of collateral improved by $249 million as $909 million fewer letters of credit were issued partly offset by increased cash posted of $660 million

This chart shows the components of changes in our collateral positions.

Cash posted to us by counterparties decreased by $151 million since December 31st, 2005 and cash we have posted to others increased by $509 million. You see the biggest increase was cash posted to exchanges. Trades done with exchanges require cash posting and, in general, contracts with bilateral counterparties allow letters of credit. As prices decreased over the course of the year, we posted more cash to exchanges and other counterparties, and reduced letters of credit posted to bilaterals. This would be exactly what you would expect to happen in a falling price environment where we have sold power to utilities and hedged the purchase with an exchange-cleared contract. The out of the moneyness of the hedge increases the cash posted with the exchanges. On balance, Constellation’s liquidity has improved since December 31st, 2005.

86

86

Synfuel Update (1)

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

$0.16

$30

($34)-

$1038%

$6412034

($90)

2006 Actual

$0.26

$47

($36)-

$930%

$8215041

($109)

2007 Estimate

Tax credit phase-out percentage

Net synfuel EPS

$60Net synfuels income

Production expenses, net of tax

Impact of phase-out

Pre-phase-out:

$6011530

($85)

2005 Actual

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)

(1) Numbers may not sum due to rounding

• Estimated phase-out in 2007 based on oil forwards and volatilities as of December 31, 2006

This chart provides an update of synfuel earnings, which have been excluded from adjusted earnings throughout the presentation. In 2006, we generated net income of $30 million or 16 cents per share compared to $60 million of net income in 2005. The decrease in net income is a result of the oil price phase-out of 38% for 2006. We have estimated the 2006 phase-out percentage based on monthly Energy Information Administration (EIA) published domestic wellhead oil prices for the ten months ended October 31, 2006 and November - December NYMEX prices for light, sweet, crude oil (which generally average approximately $6 per barrel higher than the EIA wellhead price). The actual phase-out will not be known until published by the IRS in March – April, 2007.

For 2007, we expect synfuel net income of $47 million or 26 cents per share assuming a tax credit phase-out of 30%. We have projected the phase-out based on oil forwards and volatilities as of December 31, 2006. The actual phase-out for 2007 will be dependent on actual 2007 wellhead prices and could be substantially different than our estimate as of December 31, 2006.

87

87

South Carolina Synfuel (1)

3.42.7Production (tons in millions)


$0.09

$16

($25)-

$338%

$447623

($59)

2006 Actual

$0.16

$30

($27)-

$330%

$5610028

($71)

2007 Estimate


Net synfuel EPS

Net synfuels income


Impact of phase-out

Pre-phase-out:





This chart shows the individual contribution of the South Carolina facility to overall synfuel earnings. As of the end of 2006, the South Carolina facility was operating at full production of 250,000 – 300,000 tons per month. As you can see in the top box, net income from South Carolina Synfuel before taking into account the oil price phase-out was $44 million in 2006 and is projected to be $56 million in 2007, an increase of 27%.

In the center box, we estimate that the 2006 phase-out was 38% and, based market forwards and volatilities as of December 31, 2006, we have projected a 2007 phase-out of 30% resulting in a tax credit phase-out of $28 million for 2006 and $30 million for 2007. Taking into account the benefit of reduced production expenses, the net impact of the phase out would be $25 million, or 14 cents per share in 2006, and $27 million, or 15 cents in 2007.

Overall, we project that the South Carolina facility 2007 net synfuel earnings will be 16 cents, or 7 cents higher than were realized in 2006.

88

88

Pace Synfuel (1)

1.71.4Production (tons in millions)


$0.07

$14

($9)-

$738%

$244411

($32)

2006 Actual

$0.09

$17

($9)-

$630%

$265013

($37)

2007 Estimate


Net synfuel EPS

Net synfuels income


Impact of phase-out

Pre-phase-out:





This chart shows the individual contribution of the Pace facility to overall synfuel earnings. As of the end of 2006, the Pace facility was operating at production levels of approximately 140,000 tons per month. As you can see in the top box, net income from Pace Synfuel before taking into account the oil price phase-out was $24 million in 2006 and is projected to be $26 million in 2007.

In the center box, based on the 2006 estimated phase-out of 38% and a projected phase-out of 30% for 2007, we have estimated the tax credit phase-out to be $16 million for 2006 and $15 million for 2007. Taking into account the benefit of reduced production expenses, the net impact of the phase out would be $9 million, or 5 cents per share in 2006, and $9 million, or 5 cents in 2007.

Overall, we project that the Pace facility 2007 synfuel earnings will be 9 cents, or 2 cents higher than were realized in 2006.

89

89

Impact of Sale of National Gas Plants• Sale of six national gas-fired plants closed December 2006

– High Desert in Victorville, California – 830 MW– Rio Nogales in Sequin, Texas – 800 MW– Holland in Shelby Co., Illinois – 665 MW– Big Sandy in Neal, West Virginia – 300 MW– University Park in Chicago, Illinois – 300 MW– Wolf Hills in Bristol, Virginia – 250 MW

• Financial statement impacts― Net proceeds of approximately $1.64 billion cash― Total pre-tax gain on sale of $259 million― Total after-tax gain on sale $164 million ― $117.2 million taxes to be paid in Q1 2007

• Financial statement presentation beginning in fourth quarter– High Desert reported as discontinued operations– Other plants in sale reported as continuing operations– Proceeds from sale, other than working capital, allocated between discontinued operations and

continuing operations based on relative fair value

• Divestiture will affect financial statements beginning in fourth quarter 2006

In December, we completed the sale of six of our gas-fired plants, comprising 3,145 MW of our portfolio, for net proceeds of approximately $1.64 billion in cash. The total pre-tax gain on the sale was $259 million, or $164 million after tax. The gain on sale was recorded in earnings at closing. As required by FAS 144, only High Desert earnings were reclassified as discontinued operations. The remaining plants do not qualify for discontinued operations treatment. As such, the gain on the sale of these plants was recorded in income from operations. Proceeds from the sale, other than working capital, were allocated between discontinued operations and continuing operations based on relative fair value.

90

90

Limiting Variability – Portfolio Management

$0.03

0.04

($0.01)

91%

96%

2007

Percent Hedged as of 12/30/06

0.050.03Fuel down $0.10/MMBtu, Power unchanged

($0.04)($0.01)Power down $1/MWh, Fuel unchanged

56%87%Fuel

$0.01

Sensitivity to Price Changes as of 12/30/06 ($ per share)

$0.02Power down $1/MWh, Fuel down $0.10/MMBtu

97%Power 79%

20092008

• MTM portfolio value-at-risk increased primarily due to business growth and increased volatility of commodity prices

• For 2006, MTM VaR averaged $12.7 million versus $4.7 million for 2005Note: Percent hedged includes Mid-Atlantic Fleet, Plants with PPA’s, and wholesale and retail competitive supply power businesses. Does not include gas businesses or international coal business.

Our portfolio is highly hedged as to price risk over the next three years. These hedge statistics include the Mid-Atlantic Fleet, Plants with PPA’s, and wholesale and retail competitive supply power business but excludes the gas and international coal businesses.

Since the portfolio is highly hedged and balanced, the accrual earnings represented by the competitive supply backlog provide significant visibility into our future earnings periods. We also have maintained a relatively highly hedged posture with respect to our generation fleet. By balance we mean that, if the spread between fuel (primarily coal) and power prices stay relatively constant, we will have limited financial exposure to changing commodity prices, and our outlook through 2009 should not be materially changed.

91

91

Sum-of-the-Parts Valuation Comparables• Merchant Generators(1)

– Mirant Corp. (MIR)– NRG Energy Inc. (NRG)– Reliant Energy Inc. (RRI)

• Specialty Insurers– Berkley Corp. (BER)– James River Group (JRVR)– Kingsway Financial Services (KFS)– RLI Corp. (RLI)– White Mountains Insurance Group (WTM)

• Merchant Banks– Bear Stearns Co. Inc. (BSC)– Goldman Sachs Group Inc. (GS)– Lehman Brothers Holdings Inc. (LEH)

• Regulated Utilities– Duke Energy Corp. (DUK) – Energen Corp. (EGN)– Nstar (NST)– PG&E Corp. (PCG)– Southern Co. (SO)

(1) Multiples calculated using unhedged EBITDA

This slide details the comparable companies used in our sum-of-the-parts valuation.

For Merchant Generators, the primary valuation metric is the EBITDA multiple. In our valuation, we used an estimate of unhedged EBITDA multiple range for other merchant generators, Mirant, NRG and Reliant.

For Competitive Supply we chose Berkley, James River Group, Kingsway Financial Services, RLI, and White Mountains Insurance Group as comps. We believe the activities of specialty insurers are a good comparison. In load-serving, as in specialty insurance, we absorb risks which are not yet commoditized from a loss experience data perspective. We step in between buyers and sellers of energy to accept and manage their risks with a profit margin adequate to provide an attractive return on the capital we put at risk. Risk management expertise, portfolio management and optimization are key success factors in our business as in the insurance business. The discipline to throttle back on growth rather than assume inappropriate levels of risk when competitors are driving deal pricing to unsustainable levels is important in our business as to good insurers. We are a human capital and systems intensive business.

For Risk Management and Investing, we used Bear Stearns, Goldman Sachs, and Lehman Brothers as our comps as we believe activities of energy-focused hedge funds and merchant banks provide a similar comparison.

Comparable companies for BGE are other regulated utilities including Duke, Energen, Nstar, PG&E, and Southern Co.

92

92

Additional Modeling• Financial Results

• Financial Outlook

• Commodities

– Overview p. 93 - 98

– Power p. 99 - 100

– Gas p. 101 - 102

– Coal p. 103

– Portfolio Management and Trading p. 104

– Consolidated p. 105

• NewEnergy

• Generation

• BGE

93

93

Wholesale Competitive Supply Gross Margin

$67$197$264Power Gross Margin

($143)$981$838Total

($212)$681$469Total New Business Realized in Earnings (1)

(184)434250Portfolio Management & Trading

(2)1614Coal

233053Gas

(49)201152Power

New Business (Originated & Realized)

See Appendix

(1) Includes power, gas (non-project), and coal gross margin and upstream gas project margin.

$69$300$369Total Already Originated Business (1)

2103105Hydrocarbon Gross Margin

Already Originated Business

Change20062007E($ in millions)

Overall, we are targeting realization of $838 million of wholesale competitive supply gross margin in 2007, representing a decrease of about 15% from an exceptionally strong 2006. As you can see in the top section, about $369 million will come from already originated power and hydrocarbon business. In essence, we have already achieved approximately 45% of our full-year objective.

The lower section of the table outlines our expectation for new business to be originated and realized in 2007. Wholesale power is forecast to have profits about unchanged from 2006 levels. We monetized a contract, which triggered a gain in 2006, and we had robust market conditions. We are not forecasting these to recur. The gas business will grow as we focus on delivering new investment opportunities to the Commodities Group and Constellation Energy Partners’ portfolios and focus on broadening our product offerings to producers, retailers and municipal customers.

As you’ll recall, portfolio management and trading is where we show theresults of active management of our portfolio as well as our returns on risk capital deployed in the current year. Our plan reflects a decline of $184 million in portfolio management and trading, reflecting the prudent planning assumption that strong PM&T performance of 2006 will moderate in 2007.

In total, we are forecasting new business realized in 2007 to be $469 million, down $212 million, or 31% from 2006, due to lower portfolio management and trading.

94

94

Wholesale Competitive Supply Origination

($159)

53

($212)

Change

Total Wholesale Competitive Supply Gross Margin to be Realized

504557Future Years

$1,185$1,026Total Originated

$681$469Current Year

To Be Realized In:


This chart combines our targets for new business to be realized both in the current year and in future years. We expect to originate new business of $469 million to be realized in 2007 (Current Gross Margin “CGM”) and $557 million to be realized in future years (Future Gross Margin “FGM”). In total, we expect to originate Total Gross Margin of $1,026 million to be realized in both current and future years, which is down $159 million compared to our very strong 2006 performance.

95

95

Continued Growth in Realized Gross Margin

119 186 220 300 369138108

174

247219

4893

195

434250

$0

$200

$400

$600

$800

$1,000

$1,200

2003 2004 2005 2006 2007E($

mill

ion

s)

Portfolio Management and TradingPower, Coal, and GasBacklog

(1) Gross margin excludes non-qualifying hedges and synfuel, includes upstream gas project marginSee Appendix

• Generated current gross margin of $434 million in Portfolio Management and Trading and $247 million of in Power, Coal and Gas

$981

$305$387

$589

$838

Over the past five years, we’ve seen continued growth in the level of realized gross margin from Wholesale Competitive Supply. This charts shows you the contribution each component of Wholesale Competitive Supply has made. Backlog continues to grow each year. In 2006, we have $300 million of backlog set as the foundation from which we built the rest of the years new business performance on. The power, coal, and gas businesses have increasingly contributed to gross margin growth in 2006. In total, realized gross margin for 2006 was $981 million, up about 67% from 2005 performance.

96

96

Wholesale Competitive Supply Backlog

$0

$100

$200

$300

$400

2007 2008 2009

$ in

mil

lion

s

$369

$189$170

Note: As of December 31, 2006

This chart provides an update of the backlog for our wholesale competitive supply portfolio. Backlog includes scheduled realization for power transactions and reasonable expectations for gas production. It does not include as yet unknown restructurings of existing contracts.

As you know, the portfolio is highly hedged as to price risk. On an ongoing basis, we actively manage risks such as the basis between regions or counterparty performance risk. The future year backlog that we have been originating has positioned us well, providing a highly visible stream of future earnings already originated as a solid base from which to build.

97

97

Growth in Total Gross Margin Originated

• Generated $681 million of current gross margin and created $504 million of future gross margin, 95% of which will be realized within four years

(1) Gross margin excludes non-qualifying hedges and synfuel

158 186 201369

68146987

171 197

415

504

557

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2002 2003 2004 2005 2006 2007E($

mill

ion

s)

Current Gross Margin Future Gross Margin

$245$357 $398

$784

$1,185

$1,026

Wholesale competitive supply has consistently increased both current gross margin and future gross margin origination levels since 2002. In 2006, wholesale competitive supply generated $681 million of current gross margin while booking and additional $504 million in future gross margin that will be realized in future years.

98

98

Wholesale Competitive Supply Diversified Growth

• Retained leading position in power while tripling volumes in gas and coal since 2004

% of FERC Reported Volumes*

2.6%

4.7%5.9%

7.5%8.2%

7.6%

0%

2%

4%

6%

8%

10%

2001 2002 2003 2004 2005 2006

Natural Gas Reported Volumes (Bcf/day)**

2.2

5.6

8.1

0123456789

2003 2004 2005 2006

COALPOWER GAS

Coal Deliveries (MM tons)***

5.6 5.6

12.6

17.4

02468

1012141618

2003 2004 2005 2006

*Source: Platt’s Megawatt Daily **Source: Platt’s Gas Daily ***Exclusive of agency volumes

Rank: Rank:#13 #6N/A #17 #7#5 #3 #1 #1 #1

Note: FERC reported volumes include trading volumes

In 2001, when we first began our power business, we finished the year reporting 2.6% of total FERC reported power volumes (including trading volumes) which placed us in 13th position in the industry. Over the past six years we have worked hard to increase the size and scale of our platform and grow our expertise in the power industry. At the end of 2006, we recorded 7.6% of total FERC reported power volumes (including trading volumes) which maintained our first place position as the industry leader.

In 2004 when we started the gas business, we saw a similar start, turning in 2.2% of reported natural gas volumes (including trading volumes) and ending the year in 17th position. In just two years, we have earned the rank of 6th position by reporting 8.1% of natural gas volumes.

Similarly, in the coal business, we ended our first year of business with 5.6 million tons of deliveries. In just 4 years, we’ve more than tripled our delivery to 17.4 million tons.

While we continue to focus on margins, not volumes, we believe they are indicative of levels of commercial growth.

99

99

Power: Full Requirements Market

East Target Market: 70,200 MW

Central Target Market: 48,000 MW

West Target Market: 19,500 MW

West (TX, WSCC, Can)

1,550

1,600

1,650

1,700

1,750

1,800

1,850

'06 Peak '07 OutlookP

eak

MW

s

Central (PJM, Midwest)

9,800

10,000

10,200

10,400

10,600

10,800

11,000

11,200

'06 Peak '07 Outlook

Pea

k M

Ws

East (NE, NY, SE)

5,950

6,000

6,050

6,100

6,150

'06 Peak '07 Outlook

Pea

k M

Ws

$2 - $4$2 - $4Contracted Margin Range ($ per MWh)14%13%Market Share

45% - 55%45% - 55%Load Factors18,90017,950Peak Load Served (MW)

138,000134,400Target Market (MW)2007E2006Modeling Assumptions

This chart shows our Full Requirements Power business.

Full Requirements Power includes our sales of load-following energy and capacity to distribution utilities. It’s an area we know well, with a defined base of customers, whose needs and buying patterns we understand. This business is the foundation of our wholesale power effort, and it creates an important footprint across the U.S. from which to build.

In 2007, we expect our target market and market share to grow slightly. We expect to serve approximately 18,900 megawatts in a target market of about 138,000 megawatts, resulting in market share of 14%, slightly higher than 2006.

We also expect contracted volumes to remain constant at $2.00 to $4.00 per megawatt hour.

100

100

2007 Power Gross Margin Outlook

• 63% of power gross margin target of $416 million is in the backlog

5%$398 $416 Gross Margin

(48%)$178 $92

101 72 Current Year Origination

$77 $20 Backlog Realization

Mid-Market and Structured Products

47%$220 $324

10080 Current Year Origination

$120$244Backlog Realization

Full Requirements Power


We expect 2007 realized gross margin to be $416 million, about 5% greater than 2006 which was an exceptionally strong year for this business line. We based our new business targets on reasonable assumptions and an assessment of the opportunities we see for 2007.

We expect 2007 current-year gross margin to be lower than prior year’s, but continue to expect this business to contribute meaningfully to our backlog.

101

101

Upstream Gas Assets

Black Warrior Basin CBM (AL)Woodford shale (OK) (2)Gulf Coast CBM (LA)South Texas tight sandsWyoming tight sandsFayetteville shale (AR)Williston Basin shale (MT)Shallow GOM (AL) South East Texas carbonates

• Portfolio represents 146 bcfe of proved reserves (excluding CEP)• Current daily production over 16 MMcf per day (excluding CEP)

Constellation Energy Partners Unconventional Conventional


Time

Asset Lifecycle

CEP Focus

JointFocus

Constellation Focus

0

% D

evel

oped

100

Current Portfolio Investments

% P

DP

Asset Life

Operations RiskGeological/ Geophysical Risk


Engineering Risk

Ris

k

We are developing E&P projects in various locations with unconventional production, including coalbed methane, tight sands and shale. We view Constellation Energy Partners (CEP) as an important partner to our growth strategy for upstream oil and gas. We currently owns nine assets totaling 146 Bcfe of proved reserves and generating daily production of approximately 16 MMcf per day.

Eight of the nine assets in our portfolio have 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. Accordingly, assets need to meet certain criteria to be considered for drop down to CEP. 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.

102

102

2007 Natural Gas Contribution Margin Outlook

• 28% of Natural Gas gross margin target of $74 million is in the backlog• 2006 Downstream Gas physical throughput of 7 – 8 Bcf per day

– Storage (annual): 8 Bcf– Transportation: 1 – 2 Bcf / day– Other Marketing: 5 – 6 Bcf / day

(1) Upstream Gas contribution margin


(48%)$29 $15


$17($8) Backlog Realization

Downstream Gas

31%$45 $59

18 30Current Year Origination

$27$29 Backlog Realization

Upstream Gas (1)


We expect our combined natural gas businesses to generate $74 million in 2007 gross margin.

Of that amount, $59 million will come from upstream activity and $15 million will come from our downstream business. On the upstream side, we expect to create $30 million in 2007 gross margin from current year origination, while the remaining $29 million will come from backlog realization.

We saw improvement in performance in our downstream gas business during 2006. Downstream gas physical throughput was 7 to 8 Bcf per day compared to 5 to 6 Bcf per day in 2005. Our annual storage was 8 Bcf, up from 6 Bcf in 2005. Transportation levels remained flat at 1 to 2 Bcf per day. Other marketing business resulted in 5 to 6 Bcf per day, up from 3 to 4 Bcf per day during 2005.

103

103

2007 Coal & Freight Gross Margin Outlook

• 86% of coal gross margin target of $97 million is in the backlog• 19.1 million short tons in backlog for 2007



$59 $83Backlog Realization


The gross margin outlook for our coal services business is supported by the strong backlog we created in 2006 and our current pipeline of customer business.

Our $97 million gross margin target for the coal business includes $83 million already under contract, representing 86% of our coal gross margin, and an additional $14 million to come from current year origination.

For 2007, coal backlog is 19.1 million short tons, up 68% from total backlog in 2006 of 11.4 million short tons.

104

104

Portfolio Management & Trading 2007 Gross Margin Outlook

(42%)$434$250 Gross Margin


• Portfolio management and trading reflects the results of active management of our portfolio as well as our returns on risk capital deployed

0

5

10

15

20

2005 Total Q1 2006 Q2 2006 Q3 2006 Q4 2006

Average Daily VaR (MM)

2006 average VaR: $12.7 million

Value-at-Risk: 95% Confidence Interval, One-Day

Percent Hedged: Mid-Atlantic Fleet, Plants w/ PPAs, and Power Wholesale & Retail Competitive Supply

Percent Hedged @ 12/29/06 2007 2008 2009

Power 96% 97% 79%

Fuel 91% 87% 56%

Sensitivity to Price Changes 2007 2008 2009Power down $1/MWh, Fuel unchanged ($0.01) ($0.01) ($0.04)Fuel down $0.10/MMBtu, Power unchanged $0.04 $0.03 $0.05Power down $1/ MWh, Fuel down $0.10/ MMBtu $0.03 $0.02 $0.01

This slide shows three broad metrics we use to assess our PM&T operations: mark-to-market value at risk, hedge percentages, and projected gross margin.

We closely monitor our mark-to-market value at risk. Increased levels of VaR in the 3rd and 4th quarters are attributable to increased volatility in the marketplace and the extension of our trading capability into the expanding areas of our business. Average VaR for 2006 was $12.7 million compared to an average VaR of $4.7 million in 2005.

We continue to manage a well-hedged power portfolio, with 96% of our power and 91% of our fuel hedged for 2007. As we have done in the past, as we see opportunities to increase our hedge percentages in 2008 and beyond, we will do so.

In 2006, we delivered exceptionally strong performance in PM&T, earning $434 million of gross margin, up $230 million over 2005. As the size and scope of the portfolio increases, we have an increasing information advantage and we see more opportunities to deliver gross margin through portfolio optimization and trading.

We expect $250 million from PM&T in 2007, which is a decrease from 2006 as we are not anticipating market conditions and associated opportunities to repeat themselves in 2007, but do expect to benefit from the increased scale and scope of the overall portfolio.

105

105

• In 2007, backlog realization accounts for $368 million, or 44%, of the $838 million gross margin target, up from $300 million or 40% of our original target at the beginning of 2006

Consolidated 2007 Gross Margin Outlook

(15%)$981 $838 Total(42%)$434 $250 Total Portfolio Management & Trading

434 250 Current Year Origination$0 $0 Backlog Realization

Portfolio Management & Trading29%$75 $97 Total Coal


Coal0%$74 $74 Total Natural Gas Contribution Margin


Natural Gas5%$398 $416 Total Power

201 152 Current Year Origination$197 $264Backlog Realization

PowerChange2006 (1)2007E$ in millions

(1)Gross margin excludes non-qualifying hedges and synfuel, includes upstream gas contribution marginSee Appendix

Last year was an exceptional year for the Commodities group. In 2007, we are forecasting our gross margin to decrease 15% to $838 million.

We have $368 million of gross margin in 2007 backlog, which is up $68 million year-over-year. The successful establishment of our multi-commodity platform reduces our exposure to a single commodity market and presents additional opportunities for future growth. We expect a strong year for the Commodities group, and we continue to be optimistic about our future growth prospects.

106

106



• Commodities

• NewEnergy

– Market Position p. 107

– Electric p. 108 - 110

– Gas p. 111

– Gross Margin p. 112

• Generation

• BGE

107

107

Continued NewEnergy Momentum

Source: KEMA 2006 Retailer Review – September 2006 (Q4 2006 CEG Estimate)

• With market share at end of 2006 of 24%, we are twice as large as nearest competitor

Benefits of Scale:

- Supply & risk management

- Back office costs

- Branding

- Multiple commodity product offerings

- Energy service company capabilities

- Geographic diversity

Market Share (MW)

0

4,000

8,000

12,000

16,000

Q4 2003 Q4 2004 Q4 2005 Q4 2006

NewEnergy ReliantTXU Great PlainsSUEZ Direct Energy (US Only) Pepco Hess Corp. Sempra

With market share at the end of 2006 of 24% of customers who have shopped away from their utilities in deregulated markets (the “switched market”), we are twice as large as the nearest competitor. Our strategy is different from other marketers, and our hypothesis is that scale matters.

Scale benefits virtually every aspect of the business including; enhanced supply and risk management capabilities, reduced back office costs, branding and market awareness initiatives, cross-selling opportunities with multiple product offerings, Energy Services Company (ESCO) capability, and most importantly a larger and more diverse geographic footprint.

108

108

83

96

106

2128

44

64 68

13

54

28

0

20

40

60

80

100

120

2002* 2003 2004 2005 2006 2007 2008 2009

Mill

ion

MW

h

Plan Contracted Actual Delivered

Continued Electric Volume Growth

• 66% of 2007 MWh volume under contract, consistent with percent of plan contracted at the beginning of each 2005 and 2006

13%2007 – 2009 Plan

34%2002 - 2006 Actual

CAGRTimeframe

* Pro-forma full year

NewEnergy’s megawatt hour sales have more than tripled since we acquired the business in 2002.

In 2006, NewEnergy delivered 68 million megawatt hours, slightly less than the 74 million megawatt hours we had planned driven primarily by being more selective in our customers and contracts and was more than offset by pricing improvements. For 2007, we plan to deliver 83 million megawatt hours, a 22% increase over 2006. The retail electric business picks up volume in markets transitioning at the beginning of 2007, namely Illinois, Connecticut and Pennsylvania. Sixty-six percent of electric plan volume is already contracted, slightly ahead of where we were last year. We presently have about 66 percent of this under contract which is in line with our plan and comparable to our status at this time in prior years.

We expect volumes to grow at a compound annual rate of 13% over the next 3 years.

109

109

Switched Market and Market Share Growth

28%

12%

2003-2006

11%CNE Load

6%Switched Market

2007-2009CAGR

• Market share growth expected to exceed projected switched market• Market share targeted to be around 25% over plan period

5059

6569

7984

89

1216 17 18 21 23

8

0

20

40

60

80

100

2003 2004 2005 2006 2007 2008 2009

Tho

usan

ds o

f MW

Switched Market CNE Load

During the past 3 years, the switched market growth rate has been 12% compounded and during that time NewEnergy has grown at a compound annual growth rate of 28%

Looking at 2007, we expect to see a significant increase in switched market growth primarily driven by the phenomenon of customers electing to leave utility service contracts as they expire and take advantage of lower electricity provided by deregulated providers. This is the phenomenon we told you to expect in declining price environments. We expect switching rates to moderate and return to historical levels in the subsequent years.

We anticipate the North American switched market will grow 6% annually from now to 2009 and 9% from now to 2011 driven primarily by the end of transition periods in Illinois, Connecticut and Pennsylvania utility service territories over the two year period. Overall, these growth rates are in line with KEMA’s breakout market projections & slightly above its base case scenario of approximately 5%.

We anticipate market share will improve slightly from today’s 24% over the plan period to 25%. Our projections contemplate the state of competitive markets as they stand today, including existing plans in some states for continued migration towards competitive markets. It does not contemplate new opening of additional markets, but should other states begin the deregulation discussion, we are clearly positioned to benefit.

110

110

NewEnergy: Improving Performance

Realized Electric Gross Margin (GM / MWh)

$1.00

$3.00

$5.00

$7.00

4Q06 3Q05 2Q06 2007E

Retention Rates

50%

75%

100%

4Q05 1Q06 2Q06 3Q06 4Q06 2007EIncluding 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 71% in 2006. This is in line with historical trends, and we expect the retention rate in 2007 to be 70% to 75%, in line with historical trends. Excluding customers returning to utility service, our retention rate was over 80%.

In 2006, realized electric gross margin was $4.55 per megawatt hour driven primarily by lower cost to serve customers and increased selectivity in our contracting customers. The forecast for 2007 is $3.80 per megawatt hour, mainly attributable to a return to normal "market conditions" and in line with where we are seeing our new business margins being sold.

111

111

NewEnergy: Improving Performance (Gas)Annual Load Volume (Bcf)

100

200

300

400

500

600

2005 2006 2007 2008 2009

Plan Contracted Actual

Realized Gas Gross Margin (GM / Dth)

$0.00

$0.10

$0.20

$0.30

3Q04 1Q05 3Q05 1Q06 3Q06 2007E

Retention Rates

80%

90%

100%

4Q05 1Q06 2Q06 3Q06 4Q06 2007E

Market Share (Bcf)

0

200

400

600

800

1000

2003 2004 2005 2006

SoCalGas PG&E Nicor PSE&GCMS MichCon CNEG BGE

In 2006, gas volumes were 354 Bcf, up 18% versus 2005 driven primarily by volume growth in sales and acquired business.

Looking ahead to 2007, we plan to deliver 410 Bcf, of which 74% is already under contract.

Adjusted gross margin per decatherm in 2006 was 4 cents higher than 2005, driven primarily by lower costs to serve customers.

In addition, the 2006 retention rate of 95% was robust and above the prior year rate of 92%. In 2007, we expect to maintain retention rates in the 90% to 95% range.

CNE Gas now serves over 4,000 commercial, industrial, municipal, and power generation customers. Consequently, North American switched market share in 2006 was 4.7%, up from 4.1% in 2005. We expect to grow our market share to 6% by 2009.

112

112

NewEnergy Gross Margin Reconciliation

$0.10$0.10SGA / Dth

12.9%15.2%% of Gross Receipts Tax / Gross Margin

380398Adjusted Gross Margin

$0.20$0.20Gas Gross Margin / Dth354.1410.0Volume (Dth)

$71$83Adjusted Gas Gross Margin(1)7Other Margin34-Non-Qualifying Hedges

$104$90Gross Margin Gas

$2.53$2.20SGA / MWh$4.55$3.80Electric Margin / MWh67.883.0Volume

$309$315Adjusted Electric Gross Margin(12)3Other Margin

4457Gross Receipts Tax$341$375Gross Margin

Electric

20062007E

411$465Gross Margin (Excluding Non-Qualifying Hedges)$445Gross Margin (GAAP)

Total

This charts shows you the reconciliation of NewEnergy’s GAAP Gross Margin to their Adjusted Gross Margin, which excludes other operating gross margin items such as: gross receipt tax, that is driven by sales levels, mark-to-market impacts, including economic non-qualifying hedges, consulting services revenues, and bankruptcy settlements.

As you can see, we expect adjusted electric gross margin to increase almost $6 million, or 2% from 2006 driven primarily by higher volumes. We also expect gross margin per megawatt hour to decline to $3.80 as the market returns to more normal conditions.

For the gas business, we are expecting an increase in adjusted gross margin of $12 million, or 17%, from 2006 driven primarily by higher volumes. We expect gross margin per decatherm to remain neutral year over year.

113

113

Additional Modeling

• Financial Results


• Commodities

• NewEnergy

• Generation

– Plant Statistics p. 114 - 116

– Mid-Atlantic Fleet Variable Costs p. 117 - 118

– Plants with PPAs p. 119

• BGE

114

114

Plant StatisticsCapacity

(MW) % OwnedCapacity 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 1,714 10.6% 181 CoalH. A. Wagner Anne Arundel Co., MD 963 100.0% 963 Coal/Oil/GasHandsome Lake Rockland Twp, PA 250 100.0% 250 GasKeystone Armstrong and Indiana Cos., PA 1,706 21.0% 358 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 200 100.0% 200 Oil/GasSafe Harbor Safe Harbor, PA 417 66.7% 278 HydroWestport Baltimore City, MD 116 100.0% 116 GasTotal Mid Atlantic Region 9,325 6,305

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 22 45.0% 10 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 12 50.0% 6 GeothermalMammoth Lakes G 3 Mammoth Lakes, CA 12 50.0% 6 GeothermalPanther Creek Nesquehoning, PA 80 50.0% 40 Waste CoalRio Bravo Fresno Fresno, CA 24 50.0% 12 BiomassRio Bravo Jasmin Kern Co., CA 34 50.0% 17 CoalRio Bravo Poso Kern Co., CA 34 50.0% 17 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 52 50.0% 26 Waste Coal

643 238

Total Generating Facilities 12,307 8,677

Other

Total Other

(at December 31, 2006)

Mid Atlantic Region

Plants with Power Purchase Agreements

This chart show a summary of our plant statistics in each of the areas we highlighted in the main presentation – Mid-Atlantic Fleet, Plants with PPAs, and Other / QFs.

115

115

Sunnyside (QF)26 MWWaste Coal

Rocklin (QF)12 MW

Biomass Chinese Station (QF)10 MW, Biomass

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

12 MWBiomass

Poso (QF)17 MW, Coal

Jasmin (QF)17 MW, Coal

ACE(QF)32 MW, Coal

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

Handsome Lake250 MW, 5 CTs, Gas

Panther Creek (QF)40MW, Waste Coal

Safe Harbor (EWG)278 MW, Hydro

Colver (QF)26 MW

Waste Coal

Keystone (EWG)356MW, Coal

2 MW Oil

Conemaugh (EWG)180 MW, Coal

1 MW Oil

Baltimore Plants3503 MW Coal, Gas, Oil

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 CT

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

Riverside 4, 6, 7, 8 78 MW Gas Steam (4)83 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

Soda Lake (QF)7 MW, Geothermal

Malacha (QF)16 MW, Hydro

A/C Fuels

Gary PCI

PC V. I

PC WV. I

PC WV. II

PC WV. III

Fuel Processing Plant

Western Plants

Nuclear Plants

Eastern Plants

Nine Mile Point1,553 MW Nuclear

R.E. Ginna 581 MW Nuclear

Calvert Cliffs1,735 MW Nuclear

Generation Assets – 8,677 MW as of December 2006

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

We have 78 units representing 8,677 megawatts of primarily base-load nuclear and coal generating capacity. Assets are located in high value markets like PJM and New York.

116

116

MMWh53.3Total

MMWh2.5Other

MMWh32.2Nuclear

MMWh0.1Gas

MMWh18.5Coal

CEG 2007E

Fuel Mix

MW8,677Total

MW1,512Other

MW3,869Nuclear

MW564Gas

MW2,732Coal

2006CEG

MW8,677Total

MW1,512Other

MW3,869Nuclear

MW564Gas

MW2,732Coal

2007ECEG

MMWh50.4Total

MMWh2.1Other

MMWh30.7Nuclear

MMWh0.1Gas

MMWh17.5Coal

2006CEG

Coal, 32%

Gas, 7%Nuclear,

45%

Other, 16%

Coal, 32%

Gas, 7%Nuclear,

45%

Other, 16%

Coal, 35%

Gas, 0%Nuclear, 61%

Other, 4%

Coal, 35%

Gas, 0%Nuclear, 60%

Other, 5%

Owned Capacity

Generation

(1) Excludes the gas-fired plants sold in 2006.

(1)

(1)

These charts show the fuel mix of the owned generation assets. As you can see, our primary fuels are 45% nuclear and 32% coal based on capacity, and 61% nuclear and 35% coal based on output. With the sale of the gas fired plants in December we significantly reduced the gas fuel owned capacity from 3,722 megawatts reported in December 31st, 2005 to 564 megawatts.

117

117

2006 vs. 2005 Mid-Atlantic Fleet Variable Costs

$/MWhTWh$

(Millions)$/MWhTWh$ (Millions)

$16.30

0.62

3.11

75.31

18.28

4.49

$42.28

33.4

-

-

1.1

17.6

14.7

33.4

$544

21

55

81

322

66

$1,381

2005 Plan (1)

$21.4431.3$672Total Expenses

5.21-88Emissions

124.070.674Oil/Gas/Other Gen

25.9916.9440Coal

4.6913.865Nuclear

Expenses:

0.17-5Other

$46.5131.3$1,458Total Revenue

2006 Plan (1)

(1) Includes gas plants sold in 2006Memo: Actual TWh producedNote: Does not add due to rounding

This chart shows the change in variable costs from 2005 to 2006 in the Mid-Atlantic Fleet.

Mid-Atlantic Fleet total revenue increased from $1.3 billion to $1.4 billion, or 5.6%. Gross margin per megawatt hour increased from $42.28 to $46.51, or 10%, driven by the Mid-Atlantic Fleet’s return to profitability as below market hedges began to roll off. Total expenses in the Mid-Atlantic Fleet increased from $544 million to $672 million, or 23.5% driven primarily by higher coal and gas prices.

118

118

2007E Mid-Atlantic Fleet Variable Costs

$/MWhTWh$

(Millions)$/MWhTWh$ (Millions)

$21.44

0.17

5.21

124.07

25.99

4.69

$46.51

31.3

-

-

0.6

16.9

13.8

31.3

$672

5

88

74

440

65

$1,458

2006 Plan (1)

$19.0533.3$634Total Expenses

3.80-69Emissions

76.881.182Oil/Gas/Other Gen

22.8918.0413Coal

4.5814.265Nuclear

Expenses:

0.17-6Other

$50.3633.3$1,676Total Revenue

2007E Plan

(1) Includes gas plants sold in 2006Memo: Actual TWh producedNote: Does not add due to rounding

In 2007, we project total revenue on the Mid-Atlantic Fleet to be up from 2006, as we continue to experience a benefit from the roll off of below market hedges on the fleet. We expect our revenue per megawatt hour will increase 8% from $46.51 in 2006 to $50.36 per megawatt hour in 2007.

We expect the Mid-Atlantic Fleet to decrease expenses from $672 million to $634 million in 2007, or 5.7%, driven primarily by decrease in coal and gas prices.

119

119

2007E Nuclear PPA Plants

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

83 MW uprate completed in 2006Other

June, 2014Unit 1: August, 2009Unit 2: November, 2011Contracted Through:

5.014.7TWh (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% OwnedOwnership

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.

120

120



• Commodities

• NewEnergy

• Generation

• BGE

– Overview p. 121

– Income Statement p. 122 - 123

– Electric T&D / POLR p. 124 - 127

– Gas Delivery p. 128

– Rate Base & ROE p. 129 - 130

121

121

Baltimore Gas & Electric OverviewBaltimore Gas & Electric (BGE)

10%GAAP ROE

24th18th

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

Maryland PSCFERC

Regulators- Electric & gas distribution- Electric transmission

Long-term volume growth (customer & usage)

2006 Adjusted Net income ($ millions)

2006 Rate base ($ billions)

Gas customers (millions)

Electric customers (millions)

1.0% - 1.7%

$158

$3.1

0.6

1.2

Service Area – Central Maryland

• Modest long-term growth in number of customers and customer usage• Stabilizing regulatory environment

See Appendix

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 93 companies with customers of 250,000 or more. BGE’s gas distribution business ranks 18th out of 55 companies with at least 100,000 customers.

In 2006, BGE had a rate base of approximately $3 billion and generated $158 million of net income, which translated into a GAAP ROE of about 10%. 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, which appears to be stabilizing.

122

122

2007 BGE Walk

2010686Income Tax

($35)$ 369$ 334EBIT

(6)166172Other Expenses(8)234242D & A

($0.16)$ 0.87$ 0.71Adjusted EPS (1)

($28)$ 158$ 130Net Income

01313Preferred Dividends

(13)92104Net Interest Expense

(19)497516O & M

6318324Gas Gross Margin($3)$ 1,266$ 1,263Gross Margin

($9)$ 948$ 939Electric Gross MarginChange20062007E (1)($ in millions except per share data)

Major Variance Drivers vs. 2006 +7¢ Weather (6¢) Decommissioning Expense (11¢) O&M and Other Expenses+4¢ Interest (3¢) POLR Residential Return

See Appendix

(1) Represents mid-point of guidance range

BGE electric gross margin will be lower by $9 million in 2007, primarily due to the loss of decommissioning revenue and BGE’s portion of the end of CTC collections and lower than expected POLR margins as a result of the Senate Bill One passed by the Maryland Legislature, primarily offset by an expected return to more normal weather from the temperatures experienced in 2006. The electric gross margin decline will be primarily offset by increased gas gross margins which are expected to be up $6 million driven by customer growth. In total, gross margin will be down $3 million.

For 2007, we expect to increase our expenses by $33 million, or 11 cents. The increase is driven by an increase in operational costs and higher capital expenditures associated with improving the infrastructure of the utility, primarily offset by a decrease in storm expenses as we expect a return more normal storm levels in 2007, changes in Maryland tax assessment processes, higher depreciation and interest, and other inflationary costs increases.

We project the 2007 earnings per share at the utility to be 71 cents per share, down 16 cents from 2006.

123

123

BGE Gross Margin

See Appendix

$1,266$1,263Total Gross Margin

318324Gas Margin$948$939Electric Gross Margin

$1,749$2,050Total Cost of Goods Sold

581576Gas Purchased for Resale$1,168$1,474Electricity Purchased for Resale

$3,015$3,313Total Regulated Revenue

899900Gas Revenue$2,116$2,413Electric Revenue


In 2007, we expect to generate $3.3 billion in total regulated revenue, an increase of 10% over 2006. Of this amount, $2.4 billion will be from electric revenue and $900 million will be from gas.

Our cost of goods sold is expected to be approximately $2.1 billion with electricity purchased for resale increasing 26% 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 be roughly flat with 2006, and gas gross margin is expected to increase 2%. Overall, total gross margin is expected to be flat compared to 2006.

124

124

BGE 2007 Electric T&D Overview

31,808,6011,224,271Total

$25.47730,13381360-599 KW

$33.10110,6764,3110-59 KW

$13.911,967,542118600+ KW

Industrial

$14.306,342,387498600+ KW

$24.065,579,3839,21160-599 KW

$33.063,407,494107,0210-59 KW

Commercial

$35.3413,670,9861,102,301Residential

2007 T&D / MWh Rates

2007 MWh (millions)CustomersCustomer Class

In 2007, we expect to serve 1.2 million customers approximately 31.8 GWh of electricity. Of these customers, approximately 90% are residential with the remaining 10% comprised of commercial and industrial.

125

125

BGE Electric T&D Quarterly Profile

Excludes Special ItemsSee Appendix

$430.3n/a33,292,5972007 E

Weather was milder than normal (12.9% HDD & 2.4% less CDD)$459.6(907,069)32,170,783Total

Weather was 11.4% milder than normal, 9th mildest since 195099.4(273,752)7,599,285Q4

Weather was warmer than normal (7% more CDD)136.6145,4719,126,583Q3

Weather was milder than normal (17.2% less HDD, 7.8% less CDD)

100.7(272,331)7,409,880Q2

Weather 13.2% milder than normal, 5th mildest since 1950$122.9(506,457)8,035,035Q1

2006

Comments/DriversEBITDA (millions)

MWhs vs. Normal WeatherMWhsPeriod

For 2006, EBITDA was $459.6 million with milder-than-normal weather driving lower volumes.

In 2007, assuming a return to more normal weather, we expect MWh volume usage to increase, but EBITDA to decrease by $29 million to approximately $430 million. The main drivers for the decreased EBITDA are associated with last year’s Maryland legislative actions including lost nuclear decommissioning revenues and the suspension of BGE’s residential POLR return, plus inflation.

126

126

BGE POLR 2006 Overview

$10.1$1.50$4.006.7399%Residential

Note: MWh projections are weather normalized

$23.813.55Total

0.82.252.250.375%600+ KWhourly

0.92.006.000.4354%60 – 599 KW

0.22.005.500.0884%0 – 59 KW

Industrial

600+ KW

6.32.006.003.1554%60 – 599 KW

5.62.005.502.7984%0 – 59 KW

Commercial

2006E POLR Return

POLR Return/

MWhPOLR

Adder/MWhJul. 1 – Dec. 31 POLR (MWh)

Retention

Rate

(MWh and $ in millions)

Customer Class

Residential POLR service began July 1, 2006 and our residential customer retention rate was 99%. For the year, our POLR return totaled $23.8 million, with $10.1 million being from residential customers.

127

127

BGE POLR Retention Assumptions

0.0(1) 1.504.0012.8494%Residential

Note: MWh projections are weather normalized(1) Per Senate Bill 1, Residential Return is subject to temporary suspension

10.718.13Total

0.92.252.250.405%Hourly

600+ KW

0.62.006.000.3138%60 – 599 KW

0.12.005.500.0768%0 – 59 KW

Industrial

600+ KW

4.52.006.002.2438%60 – 599 KW

4.62.005.502.2968%0 – 59 KW

Commercial

2007E POLR Return

POLR Return/ MWh

POLR Adder/MWh

2007 POLR (MWh)Retention Rate

(MWh and $ in millions)

Customer Class

This slide shows that we expect our retention rate to decrease to 94% for residential customers, as the competitive market continues to develop in Maryland and more customers may select a different supplier. Also, due to Senate Bill 1 residential return is subject to temporary suspension, thus reducing our POLR return to $10.7 million, representing collection from commercial and industrial customers only.

128

128

BGE Gas Delivery Quarterly Profile

$10.5$125.6651,1072007E

$10.1$126.8Total 2006

2.235.4640,578Q4

1.74.9637,954Q3

1.215.1637,699Q2

$5.0$71.4637,225Q12006

Gains from Cost Sharing

(millions)EBITDA (1)

(millions)CustomersPeriod

(1) EBITDA excluding off-system sales and special items

See Appendix

This slide details our gas delivery profile for 2006 broken down into quarters and provides an estimate for full year 2007 gas delivery. In 2006, gas delivery contributed $126.8 million in EBITDA. For 2007, estimated EBITDA from gas delivery is $125.6 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 $10.1 million in 2006 and are estimated to be $10.5 million in 2007.

129

129

2006 BGE Rate Base

3258192,000Total Rate Base

(334)(580)(1,933)Deductions from Rate Base

5126228Additions to Rate Base

6541,2733,705Utility Plant

TransmissionGas

DistributionElectric

Distribution($ in millions)

For 2006, our total rate base was $2 billion from electric distribution, $819 million from gas distribution, and $325 million related to transmission.

130

130

BGE ROE

(1) Includes actual gas rate case of $35.6 million

Regulated & Book ROE

9.6%11.0%9.8%BGE GAAP ROE

10.0%11.0%11.2%BGE Regulated ROE

13.3%10.8%14.3%Regulated Electric Transmission

9.6%11.0%10.8%Blended Distribution

8.7%5.3%4.7%Regulated Gas Distribution

9.7%13.6%13.7%Regulated Electric Distribution2006(1)20052004

In 2006, BGE regulated ROE was 10% and GAAP ROE was 9.6%, slightly lower than BGE’s ROE in 2004 and 2005.

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

Electric POLR Gas Sharing 2004 $6.1m $4.8m2005 $10.5m $6.4m2006 $14.3m $6.0m

131

Non-GAAP Appendix

132

132

Summary of Non-GAAP MeasuresSlide(s) Where Used Slide Containing

Non-GAAP Measure in Presentation Most Comparable GAAP Measure Reconciliation

ADJUSTED EPS Reported GAAP EPSYTD 2006 Actual 5, 17, 38, 42, 43, 52, 69, 73 133YTD 2005 Actual 6, 17, 38, 39, 52, 69 133YTD 2004 Actual 69 134Q406 Actual 37 135Q405 Actual 37 135Q106 Actual 49 1372006 and 2005 by quarter 70 136EPS Guidance 5, 17, 37, 38, 39, 42, 43, 49, 50, 52, 73, 81 133

Merchant 2006 Gross Margin 45, 74, 76, 91, 93, 102 Income from Operations / Net Income 138Merchant 2006 Below Gross Margin 76, 77 138Merchant Q406 Gross Margin 75 139Merchant Q406 Below Gross Margin 75 139Merchant Projected Gross Margin 23, 29, 31, 45, 76, 93, 95, 105 138Merchant Projected Below Gross Margin 19, 23, 24, 29, 31, 64, 76, 75 138

140Competitive Supply Gross Margin 45, 95 Income from Operations 140

BGE Gross Margin 122, 123 Income from Operations / Net Income 142BGE EBIT 122 142BGE EBITDA 125, 185 142BGE Below Gross Margin 122 142BGE Projected Gross Margin and Below Gross Margin 64, 122, 123, 125, 128 142

Debt to Total Capital 59 Debt Divided by Total Capitalization 143Projected Debt to Total Capital 59 143

Net Cash Flow before Debt Issuances (Payments) 82, 83 Operating, Investing and Financing Cash Flow 141Free Cash Flow 82, 83 141Projected Cash Flow 58, 83 141

133

133

Adjusted EPS YTD 2006 and 2005We 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 involve 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.

RECONCILIATION:Merchant Regulated Regulated Other

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

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

2006 ACTUAL RESULTS:Reported GAAP EPS 4.23$ 0.66$ 0.20$ 0.86$ 0.07$ 5.16$

Income from Discontinued Operations 1.03 - - - 0.01 1.04 GAAP MEASURESEPS Before Discontinued Operations 3.20 0.66 0.20 0.86 0.06 4.12

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

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

Adjusted EPS 2.68$ 0.67$ 0.20$ 0.87$ 0.06$ 3.61$ NON-GAAP MEASURE

2005 ACTUAL RESULTS:

Reported GAAP EPS 2.37$ 0.83$ 0.15$ 0.98$ 0.12$ 3.47$

Income from Discontinued Operations 0.42 - - - 0.11 0.53

Cumulative Effects of Changes in Accounting Principles (0.04) - - - - (0.04) GAAP MEASURES

1.99 0.83 0.15 0.98 0.01 2.98



Non-qualifying Hedges (0.14) - - - - (0.14)

Merger related transaction costs (0.06) (0.02) (0.01) (0.03) - (0.09)

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

Total Special Items and Non-qualifying Hedges 0.12 (0.02) (0.01) (0.03) - 0.09


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 and Cumulative Effects of Changes in Accounting Principles

134

134

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 involve 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.

Adjusted EPS – YTD 2004

RECONCILIATION:($ per share)

2004 ACTUAL RESULTS:

Reported GAAP EPS 3.12$

Income from Discontinued Operations 0.24 GAAP MEASURES

EPS Before Discontinued Operations 2.88

Special Items Included in Operations:

Recognition of Prior Year Synthetic Fuel Tax Credits 0.21

Synthetic fuel facility earnings 0.29

Workforce Reduction Costs (0.03)

Impairment Losses and Other Costs (0.01)

Net Loss on Sales of Investments and Other Assets (0.01)

Total Special Items 0.45

Adjusted EPS 2.43$ NON-GAAP MEASURE

135

135

RECONCILIATION:Merchant Regulated Regulated Other

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

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

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


4Q05 ACTUAL RESULTS:

Reported GAAP EPS 0.78$ 0.17$ 0.05$ 0.22$ 0.09$ 1.09$

Income from Discontinued Operations 0.10 - - - 0.09 0.19

Cumulative Effects of Changes in Accounting Principles (0.04) - - - - (0.04) GAAP MEASURES

0.72 0.17 0.05 0.22 - 0.94




Merger related transaction costs (0.06) (0.02) (0.01) (0.03) - (0.09)

Total Special Items and Non-qualifying Hedges 0.10 (0.02) (0.01) (0.03) - 0.07

Adjusted EPS 0.62$ 0.19$ 0.06$ 0.25$ -$ 0.87$ 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 ofspecial items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.




Adjusted EPS 4Q06 and 4Q05

136

136

Adjusted EPS – Prior PeriodsWe 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 involve 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.

RECONCILIATION:2005 2006

($ per share) Q1 05 Q2 05 Q3 05 Q4 05 Total Q1 06 Q2 06 Q3 06 Q4 06 Total

ACTUAL RESULTS:

Reported GAAP EPS 0.68$ 0.68$ 1.03$ 1.09$ 3.47$ 0.63$ 0.52$ 1.79$ 2.22$ 5.16$

Income from Discontinued Operations - High Desert 0.10 0.09 0.10 0.10 0.40 0.07 0.11 0.10 0.76 1.03 GAAP MEASURES

Income from Discontinued Operations - Others 0.01 0.02 0.01 0.09 0.13 - - - - 0.01

Cumulative Effects of Changes in Accounting Principles - - - (0.04) (0.04) - - - - -

0.57 0.57 0.92 0.94 2.98 0.56 0.41 1.69 1.46 4.12


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

Synthetic fuel facility results 0.07 0.09 0.08 0.10 0.33 0.02 (0.01) 0.11 0.04 0.16

Non-qualifying hedges (0.04) (0.02) (0.13) 0.06 (0.14) (0.06) - 0.20 0.07 0.21

Merger related transaction costs - - - (0.09) (0.09) (0.01) (0.03) (0.01) 0.02 (0.03)

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

Total Special Items and Non-qualifying Hedges 0.03 0.07 (0.06) 0.07 0.09 (0.05) (0.04) 0.23 0.38 0.51

Adjusted EPS 0.54$ 0.50$ 0.98$ 0.87$ 2.89$ 0.61$ 0.45$ 1.46$ 1.08$ 3.61$ NON-GAAP MEASURE


137

137


Adjusted EPS – 1Q06

Merchant Regulated Regulated OtherEnergy Electric Gas BGE Nonreg. Total

A B C D = (B+C) E F =(A+D+E) 1Q06 ACTUAL RESULTS:Reported GAAP EPS 0.24$ 0.19$ 0.19$ 0.38$ 0.01$ 0.63$ Income from Discontinued Operations - High Desert 0.07 - - - - 0.07 GAAP MEASURES

0.17 0.19 0.19 0.38 0.01 0.56 Special Items and Non-qualifying Hedges Included in Operations:

Non-qualifying Hedges (0.06) - - - - (0.06) Synthetic fuel facility results 0.02 - - - - 0.02 Merger-related Costs (0.01) - - - - (0.01) Workforce Reduction Costs - - - - - - Total Special Items and Non-qualifying Hedges (0.05) - - - - (0.05)


EPS Before Discontinued Operations

138

138

2006 Merchant Gross Margin and Below Gross MarginWe 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 believe this non-GAAP measure helps investors to better understand the changes in the level of our Merchant Energy operating results for these categories from period to period.

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 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 (34) d 411 QFs / Other 74.8 - 74.8 (22) e, f 53

Total Merchant 17,166.2$ 14,256.3$ 2,909.9$ (45)$ 2,864$

Adjustments Merchant Below Arriving At Merchant Gross Margin

Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 2,909.9$ 2,864$ Operations and maintenance expenses (1,549.4) 59 g, h, i (1,491) 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 1,116.0 Gain on initial Public Offering of CEP LLC 28.7 (29) l - Other income / (expense) 46.7 (190) b, i, j, l (143)

EBIT N/A 973 Fixed charges (191.7) 23 i, m (169)

Income Before Income Taxes 830.4 804 Income tax expense (250.2) (68) i, j, n, o (319)

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

Net Income 767.1$ 485$

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

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 $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).

** Excludes $59 million of upstream gas operating expenses included in contribution margin.

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, 2006

139

139

Q406 Merchant Gross Margin and Below Gross MarginWe 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 believe this non-GAAP measure helps investors to better understand the changes in the level of our Merchant Energy operating results for these categories from period to period.

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 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 (11) d 136 QFs / Other 14 - 14 (3) e, f 11

Total Merchant 4,166$ 3,398$ 768$ 11$ 778$

Adjustments Merchant Below Arriving At Merchant Gross Margin

Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 768$ 778$ Operations and maintenance expenses (403) 14 g, h, i (388) Merger related transaction costs (4) 4 j - Workforce reduction costs (4) 4 j - Depreciation and amortization (59) (1) h, i (59) 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 324 331.0 Gain on initial Public Offering of CEP LLC 29 (29) l - Other income / (expense) 18 (52) b, i, j, l (35)

EBIT N/A 296 Fixed charges (39) 7 i, m (32)

Income Before Income Taxes 332 264 Income tax expense (102) (3) i, j, n, o (104)

Income from Continuing Operations 230 160 Income from discontinued operations 137 (137) j -

Net Income 367$ 160$

Details of Adjustments Made in Arriving at Merchant Gross Margin:a Adjustment to remove ($102 million) gain from Mid-Atlantic Fleet and $13 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 ($5 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 $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).


Quarter Ended December 31, 2006

140

140

2005, 2004, 2003 Competitive Supply Gross MarginWe 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 believe this non-GAAP measure helps investors to better understand the changes in the level of our Merchant Energy operating results for these categories from period to period.

RECONCILIATION:

GAAP Adjustments MerchantGAAP Fuel & Purchased In Arriving Gross Margin

Competitive Supply Activities Revenues Energy Expenses Difference At Gross Margin Notes (Non-GAAP)($ millions)

Wholesale Competitive Supply 4,672.3$ 4,124.6$ 547.7$ 69$ a , b, c 617$ **Retail Competitive Supply 6,942.3 6,668.2 274.1 274 Total Competitive Supply 11,614.6$ 10,792.8$ 821.8$ 69$ -$ 891$

a Adjustment to remove $12 million from Mid-Atlantic Fleet and ($3 million) 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 $42 million loss related to economic, non-qualifying hedges of fuel adjustment clauses and gas transport contracts.c Adjustment to remove $18 million of negative gross margin associated with operating losses at our South Carolina synfuel facility.

** Excludes $28 million of upstream gas operating expenses included in contribution margin.



Wholesale Competitive Supply 3,353.8$ 3,113.4$ 240.4$ 147$ a, b 387$ Retail Competitive Supply 4,280.0 4,011.4 268.6 - 269 Total Competitive Supply 7,633.8$ 7,124.8$ 509.0$ 147$ -$ 656$

a Adjustment to remove $121 million from Mid-Atlantic Fleet and $3 million 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 $23 million of negative gross margin associated with operating losses at our South Carolina synfuel facility.



Wholesale Competitive Supply 2,703.9$ 2,553.1$ 150.8$ 154$ a, b, c 305$ Retail Competitive Supply 2,567.7 2,389.5 178.2 - 178 Total Competitive Supply 5,272$ 4,943$ 329$ 154$ -$ 483$

a Adjustment to remove $97 million from Mid-Atlantic Fleet of estimated gross margin created through active portfolio management more appropriately categorized as a competitive supply activity.

b Adjustment to remove $47 million of losses on non-qualifying, economic hedges. c Adjustment to remove $10 million of negative gross margin associated with operating losses at our South Carolina synfuel facility.




141

141

The 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.

Cash Flows – 2006 and 2005

RECONCILIATION:

YTD DECEMBER ACTUAL RESULTS:Net cash provided by operating activities (GAAP measure) 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 (3) 73 Adjusted Net Cash Provided by Operating Activities 522$ 772$ NON-GAAP MEASURE

Net cash used in investing activities (GAAP measure) 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 560 (774) NON-GAAP MEASURE

Net Cash Used in Financing Activities (Excl. Debt-Related Sources & Uses) *Common stock dividends paid (264) (229) Proceeds from issuance of common stock 84 97 Net proceeds from acquired contracts 221 537 Other financing activities, excluding SFAS 149 activities included in operating (2) 26 Adjusted Net Cash Used in Financing Activities 39 431

Net Cash Flow before Debt Issuances/(Payments) 1,121$ 429$ NON-GAAP MEASURE

Less: Proceeds from issuance of common stock (84) (97) Add: Common stock dividends paid 264 229

Free Cash Flow 1,301$ 561$ NON-GAAP MEASURE

* Total GAAP Cash Provided by Financing Activities (incl. debt-related sources & uses) was $390.7 million YTD December 2006 and $653.5 million YTD December 05.

PROJECTED CASH FLOWS:Constellation Energy is unable to provide a reconciliation of these measures for Projected 2006 because it does not prepare a forecasted statement of cash flows on a GAAP basis.

2006($ millions)

2005

142

142

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 helps investors to better understand the changes in the level of our Utility operating results from period to period.

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 2,115.9$ -$ 2,115.9$ Total Gas Revenues - 899.5 899.5 Total Regulated Revenues 2,115.9 899.5 3,015.4

Operating ExpensesPurchased Power Costs

Electricity Purchased for Resale (1,167.9) - (1,167.9) Gas Purchased for Resale - (581.5) (581.5) Total Purchased Power Costs (1,167.9) (581.5) (1,749.4)

Gross Margin 948.0 318.0 1,266.0 1,266$ Operations and maintenance expenses (351.2) (144.8) (496.0) (1) a, b (497) Merger related transaction costs (3.3) (1.4) (4.7) 5 c - Depreciation and amortization (181.5) (46.0) (227.5) (6) b (234) Taxes other than income taxes (134.9) (33.8) (168.7) 168 d -

Income From Operations 277.1 92.0 369.1 535 Other income 8.0 0.9 8.9 (174) a, c, d, e (166)

EBIT N/A N/A N/A 369 Interest expense (76.5) (26.1) (102.6) 12 e (92)

Income Before Income Taxes 208.6 66.8 275.4 277 Income tax expense (78.0) (27.0) (105.0) (2) c (106)

Net Income 130.6 39.8 170.4 171 Preference Stock Dividends (10.4) (2.8) (13.2) (13) Earnings Applicable to Common Stock 120.2$ 37.0$ 157.2$ 158$

Details of Adjustments:a Adjustment to reclassify $7 million of BGE costs required by regulation to be recorded in Other Expense to Operating Expense. b Adjustment to reclassify certain allocated costs totaling $6 million from O&M to Depreciation and Amortization.c Adjustment to remove the merger related transaction costs and related taxes that management views as a special item.d Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. e 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 948$ 318$ Operations and maintenance expenses (351) (145) Taxes other than income taxes (135) (34) Other income 8 1 Interest income in Other Income reclassed to interest expense (10) (2) EBITDA 460$ 138$



143

143

RECONCILIATION:

Total long-term debt (gross of current portion) 4,849.3$ 4,849.3$ 4,610.9$ 4,610.9$ 3,874.4$ 3,874.4$

Fair value decrease in fixed to floating rate swap included in long-term debt 7.1 0.9 -

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 - - 0.7 0.7 975.0 975.0 Unamortized discount and premium (5.9) - (8.0) - (5.2) - Subtotal 5,101.1 4,989.1 4,861.3 4,745.2 5,094.2 5,195.4 LESS: Cash - 2,289.1 - 813.0 - 72.4 Total Net Debt 5,101.1 2,700.0 35.0% 4,861.3 3,932.2 42.8% 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 - 94.5 - 22.4 - 101.8 Common shareholders' equity 4,611.7 4,611.7 4,915.5 4,915.5 3,843.6 3,843.6

Subtotal 4,801.7 4,896.2 5,105.5 5,127.9 4,033.6 4,135.4 50% Equity credit to trust preferred securities - 125.0 - 125.0 - 125.0

Total Equity 4,801.7 5,021.2 65.0% 5,105.5 5,252.9 57.2% 4,033.6 4,260.4 45.4%

Total Capitalization 9,902.8$ 7,721.2$ 100.0% 9,966.8$ 9,185.1$ 100.0% 9,127.8$ 9,383.4$ 100.0%

Exclude commodity hedge AOCI Balance from common shareholders' equity 1,379 323 (30.0) Counterparty cash collateral held reflected as a reduction of cash balance (253) (388) - Adjusted Net Debt to Total Capital 31.6% 43.7% 54.8%

PROJECTED LEVERAGE RATIOS:Constellation Energy is unable to provide a reconciliation of this measure for Projected 2006 because it does not prepare a forecasted balance sheet on a GAAP basis.

($ millions)

December 31, 2005

GAAP Balances Non-GAAP Ratio

December 31, 2001


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.

Net Debt to Total Capital

Economy & Finance

constellation energy Q4 2006 Earnings Presentation 2006 Fourth Quarter