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Constellation Energy2009 Analyst Presentation

February 18, 2009

Carim Khouzami:

Thank you. Welcome to our fourth quarter earnings call. We appreciate you being with us this morning.

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Forward Looking Statements Disclosure

Certain 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 anduncertainties 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, freight and emissions allowances and the impact of such changes on our liquidity requirements; the liquidity and competitiveness of wholesale markets for energy commodities; 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 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 ability to complete our strategic initiatives to improve our liquidity and the impact of such initiatives on our business and financial results; 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; the ability to successfully identify, finance and complete acquisitions and sales of businesses and assets; the likelihood and timing of the completion of the pending transaction with EDF and the terms and conditions of any regulatory approvals; the effect of weather and general economic and business conditions on energy supply, demand, and prices, and customers' and counterparties' ability to perform their obligations or make payments; the ability to attract and retain customers in our customer supply activities and to adequately forecast their energy usage; 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; uncertainties associated with estimating natural gas reserves, developing properties and extracting gas; regulatory or legislative developments that affect deregulation, transmission or distribution rates, demand for energy, or that would increase costs, including costs related to nuclear power plants, safety, or environmental compliance; the ability of our regulated and non-regulated businesses to comply with complex and/or changing market rules and regulations; the inability of BGE to recover all its costs associated with providing customers service; operational factors affecting the operations of our generating facilities (including nuclear facilities) and BGE’stransmission 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 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; 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.

On Slide 2, before we begin our presentation, let me remind

you that our comments today will include forward-looking

statements, which are subject to certain risks and uncertainties.

For a complete discussion of these risks, we encourage you to

read our documents on file with the SEC.

Our presentation today is being webcast, and the slides are

available on our website, which you can access at

www.constellation.com under Investor Relations.

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

Constellation Energy provides its earnings and annual earnings guidance in terms of adjusted EPS. Adjusted EPS differs from reported GAAP EPS because it excludes the cumulative effects of changes in accounting principles, discontinued operations, special items (which we define as significant items that are not related to our ongoing, underlying business or which distort comparability of results) included in operations, the impact of certain economic, non-qualifying hedges, and synfuel earnings. The mark-to-market impact of economic non-qualifying hedges is significant to reported results, but economically neutral to the company in that offsetting gains or losses on underlying accrual positions will be recognized in the future. Synfuel earnings are excluded due to the potential for oil price volatility to result in a difficult-to-forecast phase-out of tax credits. We present adjusted EPS because we believe that it is appropriate for investors to consider results excluding these items in addition to our results in accordance with GAAP. We believe this measure provides a picture of our results that is comparable among periods since it excludes the impact of items such as impairment losses, workforce reduction costs or gains and losses on the sale of assets, which may recur occasionally, but tend to be irregular as to timing, thereby distorting comparisons between periods. However, investors should note that this non-GAAP measure involves judgment by management (in particular, judgment as to what is classified as a special item or an economic, non-qualifying hedge to be excluded from adjusted earnings). This non-GAAP measure is also used to evaluate management's performance and for compensation purposes. Constellation Energy is unable to reconcile its annual earnings guidance to GAAP earnings per share because we do not predict the future impact of special items due to the difficulty of doing so. In the past, the impact of special items, economic, non-qualifying hedges, and synfuel earnings have been material to our operating results computed in accordance with GAAP. Our 2009 and 2010 guidance excludes results of the UniStar joint venture and any impact from the operations and divestiture of our international coal and freight and gas trading operations, in addition to any other special items that may occur.

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

On slide 3, you will notice we will use Non-GAAP financial

measures in this presentation to help you understand our operating

performance.

We’ve attached an Appendix to the charts on the website

reconciling Non-GAAP measures to GAAP measures.

With that, I’d like to turn the time over to Mayo Shattuck, Chairman,

President and CEO of Constellation Energy…

Turning to slide 4…

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Agenda

Topic Speaker Time

Strategic Overview Mayo Shattuck 8:30 – 8:45

Nuclear Update Mike Wallace 8:45 – 9:00

Financial Overview Jack Thayer 9:00 – 9:25

Concluding Remarks Mayo Shattuck 9:25 – 9:30

Questions & Answers All 9:30 – 10:00

Thank you, Carim. Good morning, everybody….

Let me quickly review our agenda for the morning. First, I’m going to

provide a strategic overview that will discuss the events of 2008 and

where we plan to take the company in 2009 and beyond. Mike Wallace

will then give an update on Constellation’s nuclear program and the

status of our joint venture arrangement with our partner, EDF. And

finally, Jack Thayer, our Chief Financial Officer, will review 2008 and our

prospective financials. After Jack, I’ll have some closing remarks, and

then we’ll have time for questions. So we'll start off on page five.

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This morning we reported a GAAP loss of $7.34 per share for 2008. Despite the fact that we have previously discussed the accounting impacts of our merger activities, it is still jarring to see how these items flow through our P&L. I think it is important for me to take a moment and discuss the main drivers and differentiate the actual operational aspects of this loss from those that were accounting in nature. As you can see on the chart, during 2008 we had a number of special items. The most notable is the $6.72 per share charge related to our merger activities. This charge largely consists of the conversion of the MidAmerican preferred stock and termination costs. During the year, we also reported impairment charges of $3.04 per share. These charges included the write-off of goodwill that occurred with the MidAmerican transaction and the depressed values of some holdings caused by weakened financial markets. Jack will spend some time later in the presentation walking you through the details of these charges.On the right, you can see that by excluding the special charges, our 2008 adjusted earnings would have been $3.57 per share. Turning to Slide 6…

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2008 Earnings Update2008 Adjusted to GAAP Earnings

2008 GAAP earnings were significantly impacted by a number of special items that primarily occurred during latter part of 2008

$3.57

($7.34) $6.72

$0.14$0.39$0.62

$3.04

$(8.00)

$(7.00)

$(6.00)

$(5.00)

$(4.00)

$(3.00)

$(2.00)

$(1.00)

$-

$1.00

$2.00

$3.00

$4.00EP

S

Merger & Strategic Alternative Costs

Impairment Losses & Other

Costs

BGE Maryland Settlement

Non-qualifyingHedges

Other Items Adjusted Earnings

GAAPEarnings

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During 2008, market events and internal issues helped shape and influence the decisions we made. Heading into the year, we determined that our balance sheet could not support the significant growth of our capital-intensive commodities business long-term. Accordingly, we began to explore strategic options, including the sale or JV of this business. We embarked on a process and solicited bids from interested parties. Although interest levels were high, following the collapse of Bear Stearns, we determined we would not get reasonable value for our business. As you’ll recall, at the time, most viewed this financial distress to be temporal and largely isolated incidents. We continued to believe that market fundamentals still pointed to continued increases in global demand and higher prices for commodities. We, therefore, did not reduce the extent of our commodities risk exposure at this time expecting as normalcy returned we would recommence the sales process begun early in the year. The decision resulted in record mark-to-market profits in the second quarter, however, due to their unrealized nature, the profits were largely non-cash. The volatility in commodity prices that contributed to these strong portfolio management and trading results, also required us to post incremental collateral to maintain economic hedges supporting our generation and global coal activities. The asymmetrical nature of these business’ collateral posting requirements compounded the magnitude of the problem, negatively impacting our overall liquidity. After the disclosure of the downgrade collateral error in August, we found ourselves playing catch up in a market that was showing signs of duress. While we took dramatic steps to secure incremental financing and significantly reduce our risk profile, we ultimately were unable to stay ahead of rapidly deteriorating market forces.The MidAmerican transaction was structured at a time of extreme stress. The first step in that transaction solved the liquidity problem, and the second step, which was the acquisition of the entire company, allowed us to consider other offers. The window that was left open for a topping bid, however, got smaller through the fall. The complexity of our commodities operations was the principal deterrent, but virtually all of the likely suitors also suffered deteriorating market values and access to capital. Contractually, we of course were not permitted to solicit alternative outcomes.All the while, EDF steadfastly worked on finding a solution. They had a large vested interest in us through an equity interest in Constellation and our UniStar joint venture, and had consistently expressed an interest in pursuing the acquisition of existing nuclear assets. Prior to the merger with MidAmerican, we also had extensive discussions about further investment at the parent company level. EDF’s pursuit of British Energy and our agreement with MidAmerican probably could have dampened their enthusiasm for Constellation, but they persevered, and just before the December shareholder vote, they submitted a non-conforming topping bid.Turning to slide 7…

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2008 ReviewJanuary –

JulyJuly –August

September –December

Mar

ket

Even

tsC

onst

ella

tion

Impa

ct/s

teps

take

n• Dramatic increase in

power prices and in coal prices

• Collapse of Bear Stearns, challenges with Citigroup

• Increase in volatility improves commodities profitability, increases collateral needs

• Growth in commodities outpacing Balance Sheet

• Credit concerns among banks increases

• Access to capital scarce and expensive

• Identify miscalculation of downgrade collateral metric

• Credit downgrade• Secured fully committed

financing package from RBS/UBS

• Active de-risking/ divestiture effort

• Major bank and corporate failures –AIG, LEH, ML

• No access to capital even for investment grade companies

• Major bank crisis of confidence

• Need for immediate capital leads to MEHC transaction

• Bulk de-risking activities• Weak credit markets

limits topping bids• EDF makes bid in

December

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On the surface, it seemed obvious that a $4.5 billion bid for one-half of the nuclear fleet had to be superior to a $4.7 billion deal for the whole company. However, care was required in addressing our liquidity needs, the terms of existing credit facilities, the regulatory approval process, and the prospects for real value recovery in our stock price. The negotiations with EDF validated that their bid was superior, but also enabled us to structure the transaction to allow for what we believe is real value creation for both parties in the long-term. Further, EDF was clear to indicate that this investment was an important step in the industrial strategy to enter into the U.S. marketplace.We examined the EDF price for its attractiveness on all relevant metrics. By historic norms, the $2,300 per KW paid for our nuclear fleet is greater than those of recent transactions. However, this metric fails to adjust for the specific economics of each plant, including hedges such as PPAs. A more relevant metric to look at is the multiple of hedged EBITDA paid. Using the purchase price of $4.5 billion, the 2011 EBITDA multiple is more than 10 times. This is before we include any realization in 2011 of negative value conveyed to the joint venture. As part of the agreement, at close we will be conveying negative $700 million of value on a present value basis. The present value will be calculated two days before close and will be discounted at 10%. Similar to the purchase price, the value conveyed and the discount rate are set, although the specific contracts that will be conveyed are still under discussion. We have shown on the chart what the EBITDA multiple would be if a portion of the negative value conveyed is realized in 2011.While the price to be paid for 50% of the fleet on this basis is clearly attractive for us, their offer reflects the future value of the business. I know both sides expect that the long-term value of nuclear assets will appreciate, and we will both prospectively benefit as reserve margins and carbon inevitably drive future power prices higher.Turning to slide 8…

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EDF Valuation

2011 EBITDA Multiple

Existing PPAs, sharing agreements and hedges limit near-term EBITDA

NOTE: Assumes purchase price of $4.5 billion for 49.99% of joint venture

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Balance Sheet Improvement

(Dollars in Billions) Pro Forma 12/31/08

(Pre-MEHC)Adjustments for MEHC(1)

Actual12/31/08

Adjustments for EDF(2)

Pro Forma 12/31/08

(Post-EDF)Cash $0.8 ($0.6) $0.2 $2.1 $2.3

CENG JV Investment - - - 4.5 4.5

Other assets 21.0 1.0 22.0 (5.2) 16.8

Total Assets $21.8 $0.4 $22.2 $1.4 $23.6

Liabilities $12.9 1.0 $13.9 ($2.2) $11.7

Debt 5.1 - 5.1 - 5.1

Total Liabilities $18.0 $1.0 $19.0 ($2.2) $16.8

Total Equity $3.8 ($0.6) $3.2 $3.6 $6.8

The EDF transaction increases our cash balance and reflects the fair value of our retained investment in nuclear generating assets on the balance sheet

(1) Includes proceeds from the $1B preferred note issued to EDF(2) Includes the repayment of $1B MEHC preferred note. See Additional Modeling section for more detail

While the EDF transaction represents fair value for the assets, it also

facilitates our ability to earn our way back to higher shareholder value

and allows us to consider new nuclear’s possibilities. As important, it

also offers immediate and significant restoration to the balance sheet.

The significant non-cash impact to equity of the MidAmerican break-up,

which flowed through our P&L in 2008, is more than restored with the

EDF transaction. Our book value under this transaction increases to $6.8

billion, as seen here, and our capital ratios improve significantly. Upon

completion, the transaction’s purchase accounting releases the hidden

value of our nuclear assets and right sizes their contribution to the assets

on our balance sheet. It also provides greater transparency to the

inherent value of the company.

Turning to slide 9…

99

During 2009, we will align our reporting structure to reflect the way we will manage the business in 2010 and beyond.Most are already familiar with our regulated utility, Baltimore Gas and Electric, which will continue to serve 1.2 million electric and 650,000 gas customers in Maryland. As you can see on the chart, beginning in 2010, the Merchant group will be divided into two parts to provide a more transparent view of the profitability of the businesses and how well each is being managed. Our generation assets will be split into two separate reporting units. One will be our non-nuclear generation segment which will include approximately 5,300 MWs of fossil plants and renewable facilities primarily in the PJM region. The other will be our nuclear segment that will include our 50% stake in our nuclear joint venture with EDF, which will own and operate approximately 3,900 MWs of existing nuclear facilities in PJM and New York. In addition, it will also include UniStarwhich will continue to work towards developing new nuclear facilities throughout the U.S. Our customer supply group will continue to be a leading supplier of retail and wholesale power and gas, although on a smaller, higher return, basis. In 2010, we will no longer refer to “the Commodities Group” as a distinct business. Rather, we will integrate the skills, intellectual capital and people that price physical commodities, manage risk, hedge load, and originate physical supply to be part of the Customer Supply or Generation Groups. With respect to the hedging activities in particular, starting in 2010, the Customer Supply and Generation Groups will report their earnings on an as-realized basis rather than on the current as-priced methodology for management reporting purposes. Management objectives and this reporting will allow investors to better assess the true risk and profitability of each business, providing greater visibility into our results and the way we manage our business. Turning to Slide 10…

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Preliminary 2010 Reporting Framework

Beginning in 2010, we will move to a more transparent view of business profitability and management accountability

RegulatedBusiness

GenerationAssets

CustomerSupply

Func

tions

Incl

uded

• Regulated electric T&D business

• Regulated gas distribution

• Existing nuclear and non-nuclear generating assets

• UniStar joint venture• Associated hedging

activities

• Retail power and gas• Wholesale power• Energy investments • Associated hedging

activities• Trading (for price

discovery and profit)

Bus

ines

ses

Rep

orte

d • BGE Electric• BGE Gas

• Nuclear JV• Non-Nuclear

• Customer Supply

Merchant Businesses

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As we discussed earlier, entering into a definitive agreement with EDF provides us with a path towards stability and the liquidity to remain a viable, standalone company. This transaction also further cements the relationship between our two companies. We are laser focused on closing the EDF transaction and remain excited at the prospect of what our partnership may accomplish in the future. We have also been executing on other fronts with the objective of right sizing our strategic footprint.In January and February, we executed many of the strategic divestitures we identified last Fall. The first was the announced sale of our international coal and freight business to a subsidiary of Goldman Sachs. The second and equally significant initiative was the announced sale of our Houston downstream gas business to Macquarie. Importantly, as part of this agreement, we will enter into a supply arrangement that will provide us with the gas supply needed to support our retail gas customer supply business, while reducing our credit requirement. We expect both transactions to close during the first half of 2009. Collectively, by the time we close and based on today’s market prices, we expect the combined transactions to return approximately $1 billion of currently posted collateral. In addition, we expect the divestitures to further reduce our downgrade collateral requirements by approximately $400 million. Additionally, as we has indicated in August, we have also divested a majority of our Upstream Gas properties. These are not collateral-intensive assets, however they are capital consumptive in nature. We have also made progress in our efforts to right-size our customer facing businesses to be in-line with what our balance sheet can support. The scale of these businesses will be determined by incorporating factors such as owned generation, physically contracted generation, what our maximum potential exposure could be and the cost of the capital required to support the exposure. Prospectively, our customer facing business will be smaller with higher returns, taking into account the higher cost of capital and our owned and contracted generation positions.We continue to take steps to reduce operating costs throughout our organization. In December, we announced an 8% reduction in headcount reflecting our reduced strategic footprint. We have begun a 24 month effort to streamline our systems and operations, and these actions will yield material savings. These steps to reduce corporate and business unit overhead and integrate staff functions across the organization will also improve the flow of information and operational control. We have already registered significant cost savings and operational benefits and expect to see further incremental opportunities to achieve savings.Finally, we have made the management changes necessary to focus on and execute our business strategy. Turning to slide 11…

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Strategic Actions Taken• Entered into EDF joint venture

– Provides near-term stability and liquidity needed– Ensures continued independence and public company status for Constellation– Strong partner for other opportunities

• Divested non-core, capital-intensive businesses– Announced sale of international coal and freight, and downstream gas

businesses, which will release approximately $1 billion of collateral– Improves liquidity profile and lowers downgrade collateral requirements– Divest majority of upstream gas properties

• Right-sizing customer facing businesses and fixed costs to reflect newbusiness focus– Customer facing businesses scaled to reflect Constellation’s balance sheet– Reduced corporate overhead and streamlined staff functions and systems

• Focused management team executing Constellation’s strategy

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The next 12 to 24 months will be a transition period focused on specific objectives that will help strengthen the company. We have already spoken about the importance of the EDF joint venture and will work with our partners to close this transaction as soon as possible. Our management team’s near-term focus is to return to our core strengths. These include owning and operating both nuclear and non-nuclear plants, continuing to maintain strong retail and wholesale customer relationships through our customer supply business, and continuing to provide safe and reliable utility service to our customers in Maryland. In addition, we will continue to leverage across our organization our expertise in being able to price physical assets, which we believe gives us a competitive advantage over our competitors.At the corporate level, we are also focused on balancing cash flow with earnings as we manage across all our businesses. In addition, in order to help assure that we have the near-term capital we need in extreme market conditions, we plan to maintain a liquidity cushion in excess of our downgrade collateral levels.We are committed to taking a disciplined approach in managing our collateral and liquidity. We are actively changing the way we run our businesses. Within our customer supply group, we have changed our pricing to reflect increased costs of contingent capital. With the market environment causing a reduction in competition in the markets where we are focused, we have been able to adjust our pricing and continue to write new business. We continue to take actions that will help de-risk our commodities portfolio. Jack will talk more about the specific actions we are taking to do this, but from a high level, we are repurposing and changing the objectives of our commodities group. This group will continue to provide risk management services and be used to hedge our generation fleet and to originate and secure contractual power for our retail and wholesale customer supply businesses. To a much lesser extent, we will selectively deploy risk capital and leverage our market insight and physical power strategies to earn superior risk adjusted returns. We will closely manage these activities by using strict return on capital requirements, and will report VaR deployed in this fashion and related results on a quarterly basis. Importantly, we will undertake this with a disciplined understanding of our overall liquidity needs and capabilities. Finally, we are committed to sustaining and improving our investment grade rating as we reduce the scope of our activities. All of these initiatives require near-term execution and are designed to specifically strengthen our company. Successfully executed, they allow us to maintain the flexibility we need to respond to longer-term opportunities and drive substantial future increases in shareholder value.With that, I will turn the call over to Mike Wallace, Constellation’s vice chairman. Mike…

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Strategic Focus• Focus on closing the EDF transaction by the end of 3Q 2009

• Focus on Constellation Energy’s core strengths– Own, develop and operate nuclear and non-nuclear generation assets– Maintain strong supply relationships with retail and wholesale customers– Provide reliable, regulated utility service to customers– Expertise in being able to price physical risk

• Balances cash flow with earnings– Maintain a liquidity cushion in excess to the downgrade collateral requirements

• Disciplined approach to collateral and liquidity– Price new business to reflect full cost of capital in current environment

• Commodities value-added service to enhance generation and customer supply– Continue to de-risk – Strict return on capital requirements and limits on overall exposure– Less reliance on proprietary trading

• Maintain credit metrics consistent with investment grade ratings

Constellation will focus on near-term execution while preserving the flexibility to respond to long-term opportunities

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Thank you Mayo. In this next segment, I will focus on the new joint venture with EDF, as well as our existing joint venture with UniStar Nuclear Energy.The new joint venture provides strategic entry for EDF into the key U.S. nuclear market and develops an industrial partnership and investment in Constellation. As EDF chairman and chief executive officer Pierre Gadonneix said in December, "EDF Group has long believed that there are significant benefits to be realized between the development of new nuclear assets and the operation and ownership of existing nuclear facilities, such as those owned and operated by Constellation Energy…This agreement will contribute significantly to non-CO2 emitting energy generation in the U.S.“We, too, at Constellation are excited by the prospect of what this joint venture can bring together – the largest nuclear operator in the world and a top-tier U.S. nuclear fleet that is continuing to improve year after year. In fact, let me point out to you, that as of today Calvert Cliffs Unit 2 is within 2 days of tieing the world record for continuous generation of a Pressurized Water Reactor, at 687 days. And based on the planned breaker day for its upcoming refueling outage, Calvert Cliffs 2 will set a new world record, at 691 days of continuous generation. We are proud of this kind of operational performance, and we look forward to continued excellent operational, reliability and safety performance in our new joint venture. Turning to slide 13, I will focus on our efforts to close the new joint venture…

Nuclear Update

Michael J. WallaceVice Chairman, Constellation EnergyChairman, UniStar Nuclear Energy

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Our transaction closing efforts have been initially focused on getting the required regulatory filings submitted, and indeed this effort was completed in late January. You see the list of filings on this slide, along with the anticipated timeframe for approval. The Nuclear Regulatory Commission Indirect License Transfer application is anticipated to be the gating item for regulatory approvals, and we expect this approval in the third quarter. As you may be aware, the primary focus of the NRC review is fitness to own and operate nuclear plants, financial strength and management capability, and the negation action plans to preclude foreign control or domination of licenses. CFIUS – or Committee on Foreign Investment in the United States, is an inter-agency committee of the United States government that reviews the national security implications of foreign investments in U.S. companies or operations. They will evaluate our transaction to ensure no national security impairment may arise from it. The FERC application requirements are to demonstrate that there are no adverse impacts on rates, regulation, competition; and no cross-subsidization. And the FCC filing is for the transfers of various licenses held by the three nuclear plants. We have high confidence in all of our filings, and anticipate all will be approved by the July-August timeframe.In addition to these regulatory filings, we have been engaged with state officials and are actively briefing the Maryland Public Service Commission on this transaction, maintaining a co-operative dialogue and responding to its inquiries. We believe the advantages to Maryland are significant, both in the short term and over the long term, and that this transaction does not involve any substantial influence by EDF on BGE or on the ratepayers of Maryland.Turning to slide 14…

13

Regulatory Process

= Time to Work Toward Completion/Other

CFIUS

FERC

NRC

New York State

Canada Competition

DOJ (Hart Scott Rodino)

Q1 Q2 Q3

= Time to File Application/Notice/Briefs

= Potential Extended Completion Time

6 -9 month expected close

FCC

Pennsylvania (1)

Maryland Briefing Process

(1) Pennsylvania filing only required for Safe Harbor Put Option

2/9/09: Advanced Ruling Certif. recv’d

MD PSC State/MEA 3-week extension for discovery;oral arguments 3/27/09

2/5/09: Early termination waiver recv’d

2/11/09: FCC consents recv’d

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Now I would like to describe the other commitments that EDF will make as part of the asset purchase agreement in addition to the immediate $1.0 billion cash investment. EDF and Constellation entered into a two-year asset put option that allows Constellation to sell to EDF up to $2 billion of non-nuclear generation assets. Also, EDF has provided Constellation a $600 million interim backstop liquidity facility available until regulatory approval for transfer of at least $600 million of generation assets that could be sold under the asset put option . As a demonstration of its commitment to the U.S. nuclear renaissance, and in particular, Maryland's future role in that renaissance, following the close of the joint venture, EDF will move its U.S. headquarters to Maryland. EDF will also invest $20 million in a new visitor and environmental center at Calvert Cliffs. If Calvert Cliffs Unit 3 is built, it will be one of the largest economic and industrial development projects in Maryland’s history and would meaningfully help to meet the state’s growing demand for energy. Additionally, It is estimated that each new reactor that is built would create 4,000 new construction jobs and approximately 400 permanent positions.Further, as part of its commitment to Maryland, EDF will contribute $36 million in the Constellation Energy Group Foundation to support future charitable endeavors for the long-term benefit of the Baltimore community and the state of Maryland. It is also important to note that Constellation and EDF are actively engaged in a number of implementation issues that will ensure we have an efficient, effective joint organization. Examples of these issues include the power marketing arrangements for the plants’ output, the detailed organizational structures of the joint venture, and opportunities for bringing EDF employees into the joint venture.Turning to slide 15…

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Key EDF Commitments• In addition to the $1.0 billion cash investment, EDF has provided:

– $2.0 billion (pre-tax) asset put option that allows Constellation Energy to sell EDF up to $2.0 billion in non-nuclear generation assets

– $600 million interim backstop credit facility available until regulatory approval for transfer of at least $600 million of generation assets that could be sold under the asset put option (1)

• To demonstrate its commitment to the U.S. nuclear renaissance, Maryland's future role in that renaissance, and the state of Maryland, upon closing of the joint venture, EDF will:– move its U.S. headquarters to Maryland

– invest $20 million in a new visitor and environmental center at Calvert Cliffs

– contribute $36 million in the Constellation Energy Group Foundation to support future charitable endeavors for the long-term benefit of the Baltimore community and the state of Maryland

(1) Interim backstop credit facility term is earlier of regulatory approval or June 2009

15

I would now like to update you on our UniStar joint venture. As you know, Constellation Energy took its first step towards new nuclear development activities in 2005 when we formed UniStar Nuclear, LLC to jointly market the U.S. EPR technology with Areva. Since then, we have been successfully working to position Constellation Energy and UniStar Nuclear Energy, our strategic joint venture with EDF group formed in 2007, as the leader in the U.S. nuclear renaissance. The strength of our team goes beyond our partnership with EDF. Our joint venture with Areva was the foundation for UniStar as we indicated we were pursuing four standardized units as the base fleet going forward. We identified Bechtel as the construction engineer that we will use for the U.S. EPR. We added Alstom to the team as the supplier of the turbine generators for thoseunits. Accenture was selected for our information infrastructure platform. Our approach has been to build a world-class team of strategic partners who together will assure standardization and best practices for the U.S. EPR fleet. It should be noted that each of our partners is the #1 supplier in their area of expertise in the U.S. nuclear industry.In addition, the validity of our model has been demonstrated in the market place as both Ameren and PPL engaged with us for the development of their combined license applications to the NRC. 2008 was a year of great accomplishments for the UniStar team. All four USEPR projects filed their combined license applications and have had those applications docketed by the NRC for review as such, these projects remain eligible for Production Tax Credits. All four USEPR projects submitted their Loan Guarantee applications with the DOE. And our strategic partners have demonstrated their commitments to the new nuclear renaissance in the United States through announced industrial investment: Alstom announced a $200M turbine generator facility in Chattanooga, Tennessee, potentially creating 350+ jobs; Areva has teamed with Northrop Grumman to announce a $363M facility in Newport News, Virginia to manufacture steam generators for U.S. nuclear power plants creating 540 jobs. Areva has also announced plans for a $2Billion uranium enrichment facility in Bonneville, Idaho that will create 250 jobs. And as I indicated previously, now EDF will be moving its U.S. headquarters to Maryland.New Nuclear is a legacy issue, and new nuclear is good for the country. Federal loan guarantee support for new nuclear projects could spur more than $150 billion of private sector capital investment into the U.S. economy, contributing to the build-up of U.S. manufacturing, and creating potentially tens of thousands of high-quality American jobs, and is structured to be without cost to the U.S. taxpayer. Constellation Energy is taking a leading role as the nuclear power industry is committing billions of dollars in direct, private-sector investment, and UniStar and its partners are at the forefront of the nuclear renaissance.Turning to slide 16…

15

UniStar Partners

Flamanville 3EPR

Nine Mile 3U.S. EPR

Bell Bend 1U.S. EPR

Callaway 2U.S. EPR

Calvert Cliffs 3U.S. EPR

Risk Managed Approach StandardizationTeaming Increased

Certainty

16

NRC licensing is the pacing item for the first project, Calvert Cliffs Unit 3. The NRC has published a a target date for Final Rulemaking in mid-2012. However, UniStar and Areva are working closely with the NRC to accelerate this date. We have been working proactively through the process in the state of Maryland to obtain the Certificate of Public Convenience and Necessity (CPCN), upon receipt of which we can begin preliminary site preparation work in 2009 for the Calvert Cliffs 3 plant, subject to the receipt of any other required permits or approvals. In addition, with EDF’s investment, we will also be breaking ground on the new $20 million visitor and environmental center at the site.Turning to slide 17…

16

Calvert Cliffs 3 Licensing/Permitting/Development Activities Timeline

• Combined Operating License (COL) Application was submitted to the NRC on March 17, 2008 and docketed for review on June 3, 2008

• NRC Draft Environmental Impact Statement on track for Q2 2009 issuance

• Certificate of Public Convenience and Necessity (CPCN) submitted November, 2007 and on track for Q2 2009 issuance

NRC Review

License Issued

Combined License

Commercial Operations

First Concrete

State Permit (CPCN)

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Design Certification

State Review (CPCN)

Licensing / Permitting

Development / Site WorkData Collection Detailed Design

Site Preparation

ConstructionEarly Site Work

Forgings, Nuclear Island and Turbine Generator

Orders of the Main Components

NRC Review

= Docketed for review by the NRC

Final Rulemaking

Final Safety Evaluation

Report

• COLA review process is linked to design certificationHearing

17

The DOE loan guarantee program is a critical component in funding new nuclear investment. The current program authorizes the DOE to provide loan guarantees for up to 80% of the total cost of new nuclear projects. The cost of the guarantees is paid for by the owners and is based on the creditworthiness of the project. The primary role of the government will be to provide financial assurance to the project lenders -- commercial banks and the Federal Finance Bank -- by issuing guarantees. The recent financial crisis has significantly reduced the likelihood of financing new nuclear projects without government support. The DOE loan program is the best path available to secure debt for new nuclear. We are pleased to tell you that our CC3 project was one of five selected by the DOE to move into the Due Diligence phase of the program. Further we believe current authorized funding is adequate for three projects, and that our CC3 should be one of these projects. Moreover, we are hopeful that CC3 will receive a conditional commitment before the end of this year. Constellation Energy, like many companies, currently has some constraints on the level of capital investment it can support. However, the UniStar model was developed from the start as a flexible model. As we look to EDF and other partners to work with us, we will execute a strategy that is consistent with the capital we choose to make available. UniStar is currently evaluating various capital structures and financing plans that may include: federal loan guarantees, support from export credit agencies, and sponsor or partner equity contributions. As we continue to work with DOE, we will further refine the project capital structure and financing plan.UniStar is well aware of the uncertainties and risks inherent with building a new nuclear plant, and we continue to focus on our disciplined risk managed approach to making business decisions and future commitments, and thus drive down the level of uncertainty. We have the right team of suppliers, partners and customers. We have selected the right technology, with the highest safety and security margins and licensed in both France and Finland with two units currently under construction in Europe and another two units under development in China. And we believe it is the right time – Calvert Cliffs 3 is poised and ready to proceed, as soon as the government provides lenders with loan assurance through the loan guarantee program. Turning to the slide 18…

17

DOE Loan Guarantee Expected Timeline

• Part I Submitted July 31, 2008, Part II Submitted December 18, 2008

• DOE confirmed Part II was complete on December 23, 2008

• On January 16, 2009, Calvert Cliffs 3 received DOE invitation to conduct an oral presentation of its Part II Application, on February 19, 2009

Jan ‘09 Q1 ‘09 Q2 ‘09 Q3 ‘09 Q4 ‘09

12/18/08 DOE LGA Part II Submitted

DOE Part II Application Review

DOE Loan Guarantee Negotiations

February/March: DOE Short List for Due Diligence

03/18/09 90 Day Application Update Due

Current Expiry Date for DOE Loan Guarantee Funding

Authority

Conditional Loan Guarantee Anticipated

1818

Before I turn the presentation over to Jack, I would like to make a few closing remarks. Through our new joint venture with EDF and our UniStarpartnership, we will be leveraging a partnership that is proven and successful. We have worked closely with EDF over the past two years, and we are confident our nuclear fleet will benefit from working with a large nuclear operator that knows our assets, and who is committed to making this industrial investment.Also, our relationship with EDF provides us with additional options to be a leader in new nuclear development through the UniStar joint venture as well as placing us in a leading position to take advantage of future market opportunities.Moreover, we believe Constellation has an exciting opportunity to continue its UniStar partnership with EDF in a meaningful way toward the development of new nuclear in the United States, as EDF brings construction experience, global scale and procurement leverage as the largest owner/operator of nuclear plants in the world. Also, EDF has the financial strength to support the significant capital that will be required for new nuclear construction.Lastly, we will work with EDF to help the U.S. simultaneously meet its CO2 reduction targets, while adding needed base-load capacity to answer the nation’s growing demand for carbon-free energy positioning Maryland as a leader in the future of carbon-free U.S. energy development.Now I would like to turn the presentation over to Jack for the financial overview.

18

Closing Remarks

• Through our joint venture with EDF, we will be leveraging a partnership that is proven and successful

• Relationship with EDF provides additional options– Leader in new nuclear development via UniStar joint venture

– CEG well-placed to take advantage of future opportunities

• EDF brings operational experience, global scale and procurement leverage as the world’s largest owner/operator of nuclear plants

• EDF has the financial strength to support the significant capital which will be required for new nuclear construction

• The joint venture could position Maryland as a leader in the future of carbon-free U.S. energy development

Constellation Energy is well-positioned for the carbon-constrained future with an increased national focus on energy independence

19

Financial Overview

Jonathan W. ThayerSenior Vice President and Chief Financial Officer

Constellation Energy

Thank you Mike and good morning everyone. Turning to slide 20, and I will review our financials for 2008.

20

20

Adjusted Earnings Per Share

($ per share) Q4 2008 2008

GAAP Earnings Per Share ($7.75) ($7.34)

Add: Special Items 7.71 10.54

Less: Gain on Economic Non-Qualifying Hedges 0.07 0.39

Synfuel Earnings 0.00 (0.02)

Adjusted Earnings Per Share (1) $0.03 $3.57

Significant Special Items Q4 2008 2008

Impairment Losses & Other Costs ($1.27) ($3.04)

Merger Related Costs (6.43) (6.72)

BGE Settlement 0.02 (0.62)

Other (0.03) (0.16)

Total Special Items ($7.71) ($10.54)

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

On slide 20, you see that fourth quarter GAAP earnings were a loss of $7.75 per share. Excluding special items, adjusted earnings per share for the quarter were a positive three cents per share. For the full year, GAAP earnings were a loss of $7.34 per share. Excluding special items, adjusted earnings per share for the full year were $3.57. Let me take a moment and walk you through some of the special items that negatively impacted earnings through 2008.For the full year, merger-related costs totaled $6.72 per share. These charges reflect the cash costs of $662 million and non-cash accounting charges of $542million largely consisting of the conversion of the MidAmerican preferred stock and termination costs. We also recognized approximately $3.04 of impairment charges during 2008. These charges capture the economic impact on our assets, investments and company stock of significant decreases in commodity and market prices. In the 3rd and 4th quarters we wrote down the value of our Upstream Gas assets, Constellation’s goodwill, our interest in Constellation Energy Partners, and our nuclear decommissioning trust fund. In 2008, as a result of the Maryland settlement we achieved with the Maryland PSC, BGE provided residential customers with pre-tax credits totaling approximately $189 million. This resulted in a full-year after-tax loss of 62 cents per share.Other one time items in 2008 resulted in a loss of 16 cents.Turning to slide 21…

21

21

2008 Adjusted Earnings Recap

FY 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 FY 2008

Merchant $3.77 $0.58 $1.74 $0.59 ($0.22) $2.69

BGE 0.74 0.37 0.09 0.16 0.23 0.85

Other Non-Regulated 0.09 0.00 (0.01) 0.01 0.02 0.03

Total Adjusted EPS $4.60 $0.95 $1.82 $0.76 $0.03 $3.57

See Appendix

A dramatic decline in energy commodity prices impacted results in the second half of 2008• Decline in power prices caused mark-to-market losses related to long power positions

offsetting significant gains in Q2 2008• Originated lower-than-expected new business in Q3 and Q4 reflecting focus on liquidity and

efforts to reduce scale of commodities portfolio• Rapid decline in natural gas prices impacted upstream gas values realized from divestitures

Adjusted earnings for 2008 were $3.57 per share as compared to $4.60 in 2007. During 2008, our Merchant segment was down $1.08 year over year and the Utility was up 11 cents.

At the Merchant segment, the significant increase in energy commodity prices during the second quarter led to record earnings of $1.74 per share. During the third and fourth quarter the declining price environment had the opposite effect on our portfolio. In the third and fourth quarter, we also focused on de-risking the business and not on new business origination. The full year portfolio management andtrading contribution of a loss of $139, as well as a lower level of originated new business, led to a significant year-over-year reduction in segment earnings.

The Utility turned in a solid performance in 2008. Compared to the prior year, adjusted earnings were 11 cents higher due primarily to benefits secured through the Maryland settlement and lower operating expense which were offset in part by higher bad debt and interest expense.Turning to slide 22, and a review of 2008 cash flow

22

22

2008 Consolidated Cash Flow($ in millions)

Cash Flow (Used in) Provided by Key Drivers

Operating Activities ($1,274)

- ($960) Change in net collateral and margin- ($175) Cash termination payment to MidAmerican- ($418) Cash payment in lieu of shares upon conversion to

MidAmerican preferred+ $279 Other operating sources, net

Investing Activities ($2,743)

- Approximately ($2,250) investment in PP&E and asset acquisitions- ($1,000) of restricted cash proceeds from EDF Series B Preferred for

Jan 09 paydown of MidAmerican note+ Approximately $450 proceeds from sales of assets and investments+ $57 Other investing sources, net

Financing Activities $3,123

+ Approximately $3,915 proceeds from net issuance of debt:+ $1,000 EDF Series B Preferred+ $1,000 MidAmerican 14% Note+ $450 8.625% Series A Jr. Subordinated Debentures+ $400 BGE 6.125% Notes+ $250 Zero Coupon Sr. Notes+ $815 Net issuance of short-term borrowings

- Approximately ($335) common stock dividends paid- ($457) Retirement of debt and other activity, net

Cash and Equivalents at Beginning of Period $1,096Net Decrease in Cash (894)Cash and Equivalents at End of Period $202

Collateral requirements, capital spending, the MidAmerican and EDF preferred issuances and various debt financings were the primary drivers of cash flow

Note: Subject to change pending filing of 2008 Form 10-K

During 2008, on a net basis we used $894 million of cash, resulting in an ending cash balance of $202 million at year end.Our operating activities used approximately $1.3 billion, primarily driven by increases in collateral and margin postings of approximately $1 billion during the year. Cash payments to MidAmerican of approximately $600 million also negatively impacted operating cash flow. Collectively these uses of cash more than offset the $279 million of positive cash flow from business operations.Investing activities accounted for approximately $2.7 billion of cash outflows, primarily related to capital investments, including environmental capital spending of $555 million, and asset acquisitions, including $334 million spent to acquire and build out the Hillabee, Grand Prairie and West Valley power plants. The cash proceeds of $1 billion received from the issuance of the EDF preferred stock in December is included as restricted cash proceeds, which were then used in January to retire the MidAmerican note. During the year, Constellation completed multiple financings, including $1.0 billion of preferred equity issuances to both EDF and MidAmerican as part of the respective transactions and an additional $1.1 billion of other debt issuances. Additionally the company had a net issuance of $815 million in short-term borrowings, primarily in the form of credit facility draws. Offsetting these cash in-flows were $335 million in dividend payments and $465 million related to debt retirements and other activities.Turning to slide 23…

23

Year-end 2008 net available liquidity was approximately $2.35 billionwhich compares favorably to the estimated year end downgrade collateral requirement of approximately $1.77 billion. Posted letters of credit were $3.56 billion while cash drawn against facilities was $870 million, leaving $2.15 billion in available bank facilities at the end of December. Please note that the cash balance of approximately $200 million listed above excludes the $1 billion of restricted cash received from EDF in December that was used to repay the MidAmerican $1 billion note in early January.Turning to slide 24 and a discussion regarding our efforts to reduce the scale of our commodities activities and portfolio…

23

2008 Net Available Liquidity

As of year end 2008, liquidity was $2.35 billion and the downgrade collateral requirement was estimated to be $1.77 billion

($ billions)

As of December 31,

2008Credit facilities $6.58

Less: Letters of credit issued (1) (3.56)

Less: Cash drawn on credit facilities (0.87)

Undrawn facilities $2.15

Less: Commercial paper outstanding --

Net available facilities $2.15

Add: Cash (2) 0.20

Net available liquidity $2.35

Note: Subject to change pending filing of 2008 Form 10-K(1) Includes letters of credit posted under uncommitted facilities(2) Excludes $1 billion restricted cash

24

Since September, we have taken steps to reduce the scope and scale of our commodities activities. Through these actions we have reduced margined power positions, reduced length in our trading book, reduced our exposure to commodity price fluctuations and related margining on hedges of customer supply contracts and decreased exchange and ISO collateral postings. In the top left chart, we show that we have reduced our mark-to-market value at risk by 44 percent during the fourth quarter due to reductions in our open derivative exposure and the conversion of power length to heat rate length.In the bottom left chart, you see that our efforts to reduce margined positions resulted in a decline in our collateral posting sensitivity under a price stress scenario.On the right side, we show the decline in collateral postings to exchanges and regional ISOs. Since September 19th, our initial margin posting to exchanges has declined by approximately 30 percent through year end, reflecting our reduction in exchange positions. Finally, our ISO postings have declined by 23 percent as we have actively increased our use of physical hedges and consolidated our collateral requirements when possible. As a result, we are comfortable reducing the range of potential one-time cost we could see as we reduce our commodities portfolio and resize our activities. As you will recall, in December, we signaled that we could see incremental losses of as much as a dollar per share as we reduced our portfolio. Given the success of our efforts to date, we are now comfortable reducing the potential incremental one-time cost of unwinding our commodities portfolio to 50 cents.Turning to slide 25 and a discussion of economic value at risk…

24

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Collateral delta as of 1/30/2009Collateral delta as of 11/12/2008

24

Portfolio De-Risking

Since September, we have actively reduced the scale of our commodities portfolio and our exposure to margined positions and related posted collateral volatility

1

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Mark-to-Market Value at Risk (1) Exchange Initial Margin (3)

Collateral stress decrease due to de-risking of portfolio

Collateral Stress (2)

Prescribed Price Shifts

ISO Postings

(1) The 95% confidence interval VaR is adjusted to eliminate the impact of international coal positions sold as part of our announced international divestiture(2) Prescribed price shift represents an 8-sigma price move, which equates to a parallel shift down of power, gas and coal(3) Exchange Initial Margin excludes net options value

$27 MM

$15 MM

$1,043 MM

$676 MM

2525

Looking at this chart, you can see that we have successfully reduced our economic value at risk from approximately $195 million in September to $90 million at the end of January 2009. Consistent with the flattening of our risk position discussed in the previous slide, the primary drivers of this reduction are the sale of outright power length, the conversion of power length to heat rate length and other events highlighted on this slide. It must also be noted that the unit cost of value at risk has decreased in the same period as prices and volatility have declined. In addition to reducing net positions and shrinking overall portfolio scale, we have reduced the size of our exposure to daily collateral posting by flattening our exposure to margined power positions and hedges.We remain committed to reducing the scale of our commodities portfolio, reducing our exposure to margining and will continue to update you on our progress.Turning to slide 26…

25

0

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$ in

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$90MM

1

2

Economic Value at Risk (2009 – 2013) (1)

2525

Economic Value at Risk (EVaR)

(1) Economic Value at Risk (EVaR) represents the maximum one day loss of economic value for our total portfolio assuming no new trades are executed. It is estimated as a 1-in-20 day event, or with a 95% Confidence Interval. All generation, customer supply, commodities and businesses for sale portfolio positions from 2009-2013 are included in the Economic Value at Risk calculation.

(2) Unit VaR is the Value at Risk per unit of the respective commodity and represents the cost of VaR

1

1 EVaR reduction from short gas position plus a 10 -12% reduction in Unit VaR (2)

2 EVaR reduction from sale of Upstream gas assets and a 12-15% reduction in Unit VaR

Since September, we have reduced our economic value at risk by 54 percent

26

Let me now turn to 2009 and discuss the financial initiatives that are essential to our success going forward. The EDF transaction is a transforming event and we will continue to work with our partners to close the transaction as quickly as possible. We are working diligently to finalize the new joint venture structure, giving consideration to the tax, accounting and earnings implications of different structures.As I have discussed, we are committed to a disciplined approach to our balance sheet, collateral and liquidity. In order to meet near-term needs, we will allocate capital in a prudent manner across our businesses. This includes sizing the level of business we undertake to reflect the costs of the contingent capital and working capital needed to run our business. More importantly, we will be directing capital towards business where our customers are covering the full cost of the physical and credit intermediation function we provide. This should enable us to use roughly a third of the proceeds from the EDF transaction to retire debt. We will also reserve a significant portion of these proceeds to sustain an appropriate cushion above our downgrade collateral requirement to ensure that we have the necessary capital on hand to meet the capital and credit requirements of our businesses. Efforts to reduce the strategic footprints of our business also continue.In January and February we announced the divestiture of non-strategic assets, including our international coal and freight and Houston downstream gas businesses. These sales will return approximately $1.0 billion of collateral to us based on current market prices. They will also reduce our downgrade collateral by approximately $400 million. We anticipate closing these transactions in the first half of 2009.Finally, during 2009, we will refine our reporting structure to improve transparency and help you monitor the results of each of our businesses with the expectation that we will roll this new framework out starting in 2010. Turning to slide 27…

26

2009 Financial Initiatives• Close and implement the EDF transaction

– Structure new joint venture– Finalize tax, accounting, and earnings implications

• Adjust capital structure and contingent capital to support new business strategic footprint– Appropriately size level of business activity to available liquidity and

contingent capital requirements of businesses– Retire debt– Maintain appropriate liquidity cushion above downgrade collateral

requirement• Divest non-strategic assets

– Return of collateral estimated to be approximately $1 billion– Decrease in downgrade collateral estimated to be approximately

$400 million• New reporting framework beginning in 2010

– Increased earnings visibility and transparency

27

After the challenges of 2008, cash flow is our main focus in 2009. To this end, we have identified the key risks we could face in 2009 and are carefully monitoring them and taking appropriate actions to proactively address them.We continue to see the global credit crisis and access to liquidity as our top risks. As Mayo discussed, we are actively monitoring our sources and uses of liquidity and are taking specific actions to conserve cash. We are monitoring net available liquidity and working to determine appropriate capital allocation and pricing across the business. We are carefully monitoring portfolio credit quality as the current economic environment has increased the risk of default in our retail and wholesale customer supply businesses. We have increased the monitoring of receivables and bad debt expense and are requiring deposits of all retail customers that do not meet pre-existing credit conditions. We are also adding credit restructuring and workout staff to our credit department in anticipation of higher default rates in 2009.As a leading player in the wholesale and retail markets, we will be affected by demand destruction and are monitoring demand patterns of different customer segments and geographic regions. We are enforcing the provisions in our retail contracts to minimize the impact of decreased usage.To mitigate the impact of further declines in commodity prices we have increased our hedge ratios for generation in the near to medium term. We continue to adjust these hedge ratios based on a fundamental view on price. Finally, we have reduced the overall size of our trading portfolio, adjusted positions to reflect the decline in market liquidity and are in the process of unwinding less liquid spreads to further reduce our basis risk.As you can see, we are prudently monitoring risks and will track performance and update you on our progress as we move forward.Turning to slide 28, and our liquidity…

27

2009 Risk Mitigation Activities

Global Financial and Credit Market Crisis

Risks

Portfolio Credit Quality

Market Liquidity

Commodity Price Declines

Demand Destruction

Actions

• Decreased the size of the trading portfolio• Adjusted limits on financial position size by market and term• Unwound spreads to more liquid hubs

• Developed probabilistic stress of net available liquidity given price sensitive collateral and gross margin

• Redeploying capital incorporating revised assumptions about future collateral requirements

• Planned for incremental bad debt expense in 2009 in anticipation of worsening retail credit delinquencies and defaults

• Require deposits for all new retail customers that do not meet pre-existing credit conditions • Currently pursuing insurance and third-party sales of asset pools• Increase credit restructuring and workout staff in anticipation of higher default rates in 2009

• Adjusted load forecasts to reflect a more pessimistic outlook • Monitoring usage and revenues• Enforcing bandwidth clauses in retail contracts

• Increased generation hedge ratios in 2010 to 2012 to reduce variability of future cash flows

• Reduced sensitivity to collateralized positions

28

A key component of our 2009 improved liquidity story will be thesettlement of our mark-to-market assets. This chart assumes forward prices realize and no incremental new business is added. Under this assumed scenario, we expect to realize over $500 million in cash due to the settlement of our mark-to-market positions in 2009. We expect the cash realization of mark-to-market gains that were recorded in previous periods to improve available liquidity over the next 3 years. Turning to slide 29…

28

Liquidity Returns from Mark-to-Market Assets

Approximately $1 billion of liquidity is expected to return over the next three years

Note: Excludes international coal and freight and Houston downstream gas businesses

Settlement of Mark‐to‐Market Assets(as of 12/31/08)

$0

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illions

29

In addition to realized mark-to-market cash profits, the settlement and realization of 2009 positions is estimated to return $1.2 billion of collateral across our total merchant portfolio.An incremental $800 million of collateral is expected to be returned in 2010.New business will partially offset this collateral realization. We expect to size this level of business in accordance with our balance sheet and access to capital.Turning to slide 30…

29

Forecast of Collateral Use

Excluding the impact of businesses that will be divested, approximately 36% of our total collateral posted will be returned by the end of 2009

Note: Excludes international coal and freight and Houston downstream gas collateral use

$-

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Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10

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Collateral Roll Off (as of 12/31/08)

LC Cash

30

I have spoken at length this morning regarding our collateral postings. As of December 31, 2008, our net collateral postings were approximately $4.5 billion. Although collateral postings are highly dependent upon commodity price movements and business activities, as of December 31st, the largest user of collateral was our Customer Supply business, reflecting the dramatic decline in power prices in the fourth quarter. Going forward, we expect to reduce the amount of collateral we post in order to support our business activities. By the end of the second quarter, we expect to have completed the sales of our International Coal and Freight and Houston downstream gas businesses, which require an estimated $1 billion in collateral support. Prospectively, in our Customer Supply business, we are pursuing a smaller, higher return business sized relative to owned and contracted physical generation. These actions will result in greatly reduced levels of posted collateral as compared to hedging with financial contracts. The chart on the right, assuming no changes in underlying commodity prices, shows our projected use of collateral by business at the end of 2009. By year end, we expect total collateral use to be approximately $2.8 billion across generation, customer supply and commodities. As you can see commodities, which by then will have been reduced in scale, will use a very small amount of net collateral. Turning to slide 31 and a review of our projected available liquidity…

30

Collateral Use by Activity

UK4%

Commodities Group20%

Generation andCustomer Supply (1)

56%

Houston21%

Following the close of our announced non-strategic asset sales and the continued reduction of our commodity portfolio, our collateral posted is expected to decline from roughly $4.5

billion at the end of 2008 to approximately $2.8 billion at the end of 2009(1) Customer Supply hedges includes $400MM of CNE ISO collateral. Generation includes $200MM in support of corporate bonds.(2) Projection based on roll-off of existing collateral and divestiture assuming prices (as of 12/31/08) are constant

Estimates as of December 31, 2008 (1) Projected for December 31, 2009 (2)

$4.5 billion Approximately $2.8 billion

31

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Projected 2009-2010 Net Available Liquidity (1)

Available Facilities Cash Downgrade Collateral

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available (estimated after-taxproceeds of $0.6B)

- $600M EDF interim facilityexpires with put availability

Dec-09 reflects:- $1B additional voluntary debt retirement Dec-10 reflects:

- $2B Expiration of EDF put option (estimated after-tax proceeds of $1.5B)

Downgrade collateral steps down as UK and Houston divestitures completed

(1) Reflects net collateral roll off based upon current commodity prices and positions of approximately $1.7 billion in 2009, and approximately $0.5 billion in 2010, and assumes collateral acceleration related to UK and Houston divestitures

Sep-09 reflects:+ $3.1B CENG JV investment estimated after-tax proceeds+ $0.3B put option with EDF available (estimated after-tax proceeds of $0.3B) for remaining asset- $3.3B reduction in credit facility capacity due to completion of CENG JV- $500M CEG bond matures- $1B EDF preferred matures

Jun-09 reflects:+ UK and Houston divestitures to

occur in Q2+ Additional $0.9B put option with

EDF available (estimated after-tax proceeds of $0.6)

Here we forecast our net liquidity, by quarter, for 2009 and 2010. The significant 2009 improvements in liquidity are driven primarily by the addition of the EDF put option, the roll-off of margined positions and the second quarter divestiture of the Houston and international businesses. The EDF transaction is expected to close in September and result in a net reduction of liquidity. Drivers include the subsequent repayment of debt and reduced credit facilities triggered by the sale of a portion of our nuclear assets to EDF. Given the reduction in credit facilities, we plan to use cash from proceeds to post collateral if letter of credit capacity is not sufficient. We see a further expected reduction in liquidity in the fourth quarter from the expected voluntary repayment of $1 billion of debt.Looking at 2010, we expect increased free cash flow combined with the roll off of letter of credit collateral to result in an improving liquidity profile for the first three quarters. However with the expiration of the $2 billion put at year end, projected liquidity falls to approximately $2.0 billion. We will address this issue during the next two years as we refine strategy and capital structure.Turning to slide 32…

3232

In our forecasts, we consider both expected outcomes and stressed scenarios. Here we measure our net available liquidity position under stress scenarios. In this graph, 2009 monthly net available liquidity is expanded from the previous page but shown here as the red line. We have added our downgrade collateral requirement – assumed to be $1.8 billion through March and falling to $1.4 billion by May – to the stressed business scenario. These stress results are approximately 20 percent lower than our stress analysis performed 5 weeks ago and reflect a similar reduction in margined 2009 positions. Further reductions in our marginable power positions will reduce our collateral sensitivity to commodity price changes. Based on a Monte Carlo price simulation at a 95% confidence level, we have stressed key price sensitive sources and uses of net available liquidity including existing business collateral needs, customer supply new business collateral needs, and gross margin realization variability. We have also stressed capital and O&M expense variability and contingent wholesale credit capital needs. As you can see we have adequate available liquidity even in stress scenarios in 2009. Although not pictured here, the same is true in 2010.Turning to slide 33…

323232

Liquidity Stress

Liquidity is expected to adequately cover stressed business uses going forward(1) The Net Available Liquidity Forecast assumes the UK and Houston businesses are sold in April 2009. Stress is based on a 95% confidence level price

simulation impact on the major price sensitive components of our sources and uses of liquidity.

Reflects $1B early debt retirement

Net Available Liquidity Forecast (1)$

billi

ons

33

Having addressed liquidity, lets turn to earnings. We are projecting 2009 earnings per share of $2.90 to $3.20 per share. This is roughly in-line with the guidance we provided in December, although we have backed off the high end of our range by ten cents to reflect the steps taken to hedge the fleet in a declining price environment.These figures exclude the economic impact of our divested properties. For comparability, year over year, we provide a second column that shows our guidance excluding the impact of the share dilution caused by the issuance of approximately 20 million shares to MidAmerican in December 2008. Before dilution, the midpoint of our Merchant segment guidance range is below our 2008 results of $2.69 per share driven by the impact of a reduced level of Wholesale Power gross margin as well as higher interest expense partially offset by lower costs. Generation is expected to be relatively flat with higher gross margin due to the roll-off of below-market hedges offset by the impact of the expected EBIT lost to the formation of the nuclear joint venture.Before dilution, our Utility segment guidance is in-line with 2008 results of 85 cents per share. We expect higher electric distribution revenues to be offset by higher expenses related to inflation and higher interest expense.As noted, starting in 2009, we will exclude UniStar equity in earnings from our reported adjusted results. As a development stage joint venture, in which we recognize non-cash equity in earnings, UniStar’s results are not expected to be relevant in understanding Constellation's earnings or in the valuation of Constellation. The non-cash equity in earnings is expected to be a loss of 8 cents per share in 2009 compared to a loss of 2 cents in 2008. The 2009 earnings guidance range also excludes any impact of the recently announced sale of our International Coal & Freight and downstream gas trading businesses and any results of operations of these businesses prior to close.Turning to slide 34…and a review of projected earnings by segment…

33

2009 Earnings Profile

($ per share)2009E

Incl. Dilution (1)2009E

Ex. Dilution (1) 2008 (2)

Merchant $2.10 – $2.40 $2.35 – $2.65 $2.69

Utility 0.70 – 0.80 0.80 – 0.90 0.85

Other Non-regulated 0.02 – 0.04 0.04 – 0.06 0.03

Total Adjusted EPS $2.90 - $3.20 $3.25 - $3.55 $3.57

(1) Excludes special items such as EDF transaction fees and amortization of the increase to fair value of the CEG retained nuclear assets. Also excludes UniStar earnings of ($.08) in 2009. 2008 includes UniStar earnings of ($0.02). From 2009 – 2013, UniStar projected earnings range from ($0.08) to ($0.13).

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

Key variance drivers:• Merchant: Higher interest expense and lower wholesale power gross margin, partially

offset by lower costs • Utility: Higher electric distribution revenue offset by higher expenses

34

BGE will invest in the PSC-approved energy efficiency programs for customers in 2009. These programs are a component of our strategy to meet the Empower MD goals and designed to deliver savings to customers. This year BGE will continue to deploy smart thermostats and load control switches to electric residential customers and continue its smart energy pricing pilot. These programs will deliver savings to customers while providing BGE with appropriate cost recovery, including a reasonable return on invested capital. With the implementation of large commercial and industrial electric decoupling in early 2009, BGE’s electric and gas delivery revenues address the disincentive of energy efficiency. Importantly, BGE’s decoupling mechanism allows it to retain the value of future customer growth. This important policy change aligns BGE’s interests with those of its customers and regulators in the pursuit of Maryland’s stated energy efficiency goals.The decoupling decision and the recent approval of one-year amortization of expected 2009 energy efficiency program costs are working examples of our improved relationship with the Maryland PSC. These decisions balance the energy needs of consumers with the financial health of the utility.During late 2009, BGE intends to seek rate increases as permitted under the March 2008 Settlement between Constellation, BGE and Maryland’s political and regulatory leaders. This would likely be effective in 2010 and would be our first electric rate increase since 1992. The increase is capped at five percent.Turning to slide 35…

34

BGE 2009 • Smart Energy Savers ProgramSM continues to move forward in support

of Empower MD goals – PSC approved all of BGE’s energy efficiency programs in December 2008

with programs to begin in 2009– Residential customers continue to enroll in Peak RewardsSM program– Smart Energy Pricing pilot will continue in 2009

• Implemented electric revenue decoupling for large commercial andindustrial customers and a lost sales tracker for the largest customers– $950 million of 2009 electric and gas delivery revenue decoupled

• Recent supportive regulatory decisions for BGE that sustain the financial health of the utility

• File a combined gas and electric distribution rate case in 2009 as agreed upon in the 2008 settlement– Electric rate case increase capped at five percent– First rate case filed since 1992 for electric; 2005 for gas

Appropriate cost recovery, including reasonable rates of return, will enable BGE to continue to make infrastructure investments and support Empower MD initiatives

35

This chart presents our generation earnings outlook without taking into effect the impact of the joint venture. The chart provides an update on how changes in market forward prices and hedging activity affectGeneration EBITDA. For 2009, Generation is forecasting unhedgedEBITDA of $1.4 billion. Netting the hedging impacts of approximately negative $400 million, hedged EBITDA is forecast to be about $1.0 billion. The current hedged EBITDA forecast for Generation is $1.2 billion in 2012. As you can see at the bottom of the chart we are maintaining high annual hedge percentages over the next two years in an effort to insulate cash flow and earnings from declining commodity prices.Turning to slide 36…

35

Generation Earnings Outlook (pre-EDF JV)($ millions) 2009E 2010E 2011E 2012ETotal Output (MM MWh’s)Unhedged GM

NuclearNon-Nuclear

51

1,822780

53

1,921868

53

1,911810

53

1,888797

O&MNuclearNon-Nuclear

(799)(360)

(801)(413)

(838)(430)

(885)(412)

Unhedged EBITDA

Hedges

1,443 1,574 1,453 1,388

PPA/RSA (210) (217) (236) (191)

Other Hedges (235) (400) (66) (44)

Hedged EBITDA

Hedge % (1)

998

100%

957

91%

1,151

56%

1,152

44%

(1) As of February 3, 2009

Since the third quarter, we have increased our hedge profile to provide greater cash flow and earnings stability

3636

The Customer Supply Group is focused on appropriately pricing risk, reducing capital needs and earning appropriate returns on capital. We are underwriting new business in a fashion that passes through the increased cost of physical and credit intermediation risks to our customers and enables us to earn an appropriate return on our invested capital. Further, we will continually review our credit policies and adjust for current economic conditions. These actions include requiring deposits from new retail customers that do not meet pre-existing credit conditions.By focusing retail power growth in markets where we already own or can contract for generation, we expect to reduce the margin requirements in our businesses. We will continue to pursue wholesale and mid-marketing transactions that are collateral efficient. In addition, we plan to finalize a gas supply agreement with Macquarie Cook Energy which will free up approximately $450 million (at today’s prices) associated with the retail gas business, which is an important component of the $1 billion collateral return previously discussed. From a cost perspective, in 2008 we streamlined this business and reduced operating costs. These efforts will continue in 2009 as we work to leverage scale and standardize processes and products to further improve efficiency and profitability. Turning to slide 37…

36

Customer Supply 2009 and Beyond• Disciplined underwriting standards and pricing of risk

– Incorporate cost of capital, customer size and complexity in pricing decisions– Require deposits from new retail customers that do not meet pre-existing

credit conditions– Reduce capital and contingent capital footprint– Focus retail power growth in markets where we own or can contract

generation, thereby reducing collateral needs– Pursue structured transactions that hedge in a collateral efficient manner– Enter into gas supply arrangement to minimize collateral exposure to

commodity prices• Position business to earn greater returns

– Streamline products, services and operations while providing leading risk management and execution services

– Increase scale in attractive retail gas and power markets with plans to exit low return markets such as Canada

– Expand sales of higher margin, value-added products

The Customer Supply Group will optimize deployed risk capital, reduce geographic footprint and position the business to earn greater returns

37

As Mayo discussed, Constellation has repurposed and fundamentally changed the commodities group’s objectives. We expect structured products backlog to contribute $156 million of gross margin in 2009. While we are resizing the scope and scale of this business, we continue to believe that the intellectual capital embedded in this organization provides Constellation with a durable competitive advantage in our cyclical, commodity-intensive business.In addition to serving as the risk clearinghouse for all commercial activities, commodities group’s results will continue to incorporate the expected results of deploying small amounts of risk capital for proprietary trading and investment purposes. We expect $18 million of gross margin from portfolio management and trading in 2009. This is a significant reduction from our 2008 business plan level of $392 million. Importantly, the same team that has successfully reduced and flattened the trading portfolio will be charged with deploying prospective speculative risk capital.While we have divested substantial aspects of our commodities business, we have retained certain aspects that we will look to exit. This includes certain upstream gas properties and our shipping joint venture with the Restis Group as well as gas transport positions within our physical gas marketing business. These retained investments will have minimal impact on our 2009 earnings. Turning to slide 38…

37

Contribution Margin ($ in millions) 2009E

Structured Products Backlog $156

Portfolio Management and Trading 18

Subtotal Core Commodities $174

Retained Investments

International Coal and Freight ($4)

Gas Marketing and Trading 0

Gas E&P 6

Total Commodities Contribution Margin $176

Operating Expenses (99)

EBIT $77

Commodities 2009

Smaller commodities function continues to contribute to earnings

3838

In 2009, capital spending is expected to decrease by approximately $400 million to $1.8 billion, primarily related to reduced majorenvironmental and generation spend in the merchant segment. In 2010, capital spending is forecasted to be $1.5 billion. The decline is due to the completion of major environmental projects and the Hillabee power plant. This is partially offset by spending on BGE’s Smart Energy Savers SM initiatives including advanced metering and demand response.After the close of the nuclear joint venture with EDF, approximately $400 to $500 million of annual capital spend will move to the joint venture.case-by-case basis as opportunities are identified andavailable and projected liquidity permits investing.Additional new growth investment will be considered on a case by case basis as opportunities are identified and available and projected liquidity permits investing.Turning to slide 39…

38

Capital Spending

($ in millions) 2008 (1) 2009E 2010E

Merchant Total $1,675 $1,321 $744

Utility Total 462 452 716

Other Non-regulated / Corporate 86 37 40

Total Capital Expenditures $2,223 $1,810 $1,500

Key drivers of change 2008 to 2010:• The reduction in Merchant capital expenditures is mainly driven by the completion of major

environmental projects and completion of Hillabee plant construction • Increase in BGE capital spending driven by Smart Energy Savers ProgramSM (Demand

Response Initiative, Conservation and Advanced Metering Initiative) (1) Excludes Nufcor and Wesco acquisitions

Nuclear JV Capital - 80 429

CEG Capital Excluding Nuclear JV $2,223 $1,730 $1,071

39

Our projections for 2009 and the associated balance sheet and credit metrics are shown here adjusted for the joint venture with EDF. Going forward, we expect our businesses to generate significant excess cash flow after dividends, allowing us to deleverage and strengthen our balance sheet.Our projected 2009 credit metrics are driven primarily by a substantial reduction in leverage and improvements in FFO. In addition to the January 2009 repayment of the $1 billion MidAmerican note, we expect to retire $500 million of debt in September, the $1 billion EDF preferred security and up to $1 billion of incremental debt by year-end. We expect FFO to improve in 2009 from the realization of previously originated mark-to-market contracts.2009 Debt to Adjusted Total Capital, including imputed debt, is expected to be 42%-46% and in the 29% to 33% range excluding imputed debt. In addition to planned debt reductions in 2009, Constellation’s Debt to Adjusted Total Capital ratio will also benefit from a gain on the sale of 49.99% of the nuclear joint venture. Turning to slide 40…

39

Balance Sheet Metrics 2009

(1) Based on our assumption of the S&P methodology(2) Includes BGE rate stabilization securitization debt(3) 2009 equity balance reflects estimated net gain on sale of 49.99% of CENG(4) Based on S&P’s methodology for FFO computation. FFO is adjusted when calculating metrics excluding imputed debt(5) Based on most recently published S&P imputed debt balance and company estimate for BGE imputed debt(6) Excludes BGE Rate Stabilization Securitization debt, AOCI balance related to cash flow hedges of commodity transactions(7) Excludes BGE Rate Stabilization Securitization debt Note: Numbers may not add due to rounding

($ in billions) Merchant BGEConsolidated

CEG

Debt

Total Adjusted Debt (2) $2.3 $2.7 $4.9

Capital

50% Hybrid & Preferred Securities 0.2 0.1 0.4

Equity (3) 5.9 1.9 7.8

Total Capital $8.4 $4.7 $13.1

FFO (4) $1.1 $0.5 $1.5

Imputed Debt (5) $2.8 $0.4 $3.2

Metrics Excluding Imputed Debt

Debt to Adjusted Total Capital (6) 21% – 25% 50% – 54% 29% – 33%

FFO to Debt (7) 45% – 49% 21% – 25% 33% – 37%

FFO to Interest Coverage 3.5x – 4.0x 4.2x – 4.7x 3.7x – 4.2x

Metrics including Imputed Debt

Debt to Adjusted Total Capital (6) 30% – 34% 54% – 58% 42% – 46%

FFO to Debt (7) 19% – 23% 16% – 20% 18% – 22%

FFO to Interest Coverage 2.9x – 3.4x 3.9x – 4.4x 3.1x – 3.6x

(1)

40

40

2009E Consolidated Cash Flow

($ in billions) Cash Flow (Used in)

Provided by Key Drivers

Operating Activities $2.0

+ $1.2 Net income, excluding non-cash items+ $0.9 Working capital sources (key drivers include realization of MTM

contracts(1), net change in AR and AP(1), and net collateral rolloff of contracted positions(1) offset by anticipated new business)

- ($0.1) Other operating uses (includes pension funding)

Investing Activities $2.4

+ $3.1 After-tax proceeds received from EDF+ $1.0 Reduction in restricted cash used to repay MidAmerican note- Approximately ($1.7) capital expenditures- International and downstream asset sales proceeds assumed to be

zero

Financing Activities ($3.2)

- ($1.0) for repayment of EDF Series B preferred - ($1.0) for repayment of MEHC note- ($0.5) for retirement of 6.125% note- ($1.0) assumed paydown of other debt- ($0.2) dividends+ $0.5 assumed debt issuance for remarketed tax-exempts, reserve-

based lending facility, BGE and other financing activities

(1) Based upon commodity prices and positions as of 12/31/08Numbers may not add due to rounding

Cash and Equivalents at Beginning of Period $0.2

Net Increase in Cash 1.2

Cash and Equivalents at End of Period $1.4

We expect to increase cash by approximately $1.2 billion in 2009. The largest driver is the sale of 49.99% of our nuclear business to EDF which is expected to result in after-tax cash inflow of over $2.1 billion, after repayment of the EDF preferred.We are forecasting an operating cash inflow for the year of approximately $2.0 billion after accounting for the joint venture. The biggest drivers of the consolidated operating cash flow are the expected current year net income and mark-to-market contract realizations.Investing cash flows for the year are forecasted to be approximately $2.4 billion, driven by $3.1 billion of after-tax proceeds related to the nuclear asset sale to EDF and the release of $1 billion of restricted cash to pay off the MidAmerican note, offset in part by capital spending of approximately $1.7 billion. Financing cash flows are forecasted to use approximately $3.2 billion as the company repays debt over the course of the year. Payments to EDF and MidAmerican, combined with a scheduled retirement of a $500 million note, as well as a voluntary retirement of another $1 billion are the primary drivers. Financing cash flows in 2009 receive a benefit as compared to 2008 from the reduction of the dividend from $1.91 per share to 96 cents. The annual estimated savings of this reduction is approximately $190 million. Turning to slide 41…

41

Let me close by taking a moment to talk about 2009 and beyond guidance. For 2009, as previously discussed, we expect earnings per share to be in the range of $2.90 to $3.20 per share. For 2010, we are expecting earnings per share to be in the range of $3.05 to $3.45 per share. As we continue to finalize our joint venture structure with EDF we will update you and revise our guidance asnecessary.As currently hedged, in 2011 and beyond, Constellation’s earnings are increasingly leveraged to dark spreads and heat rates. We show our exposures on the right side of the slide. In 2012, as PPAs roll-off, we are increasingly sensitive to power prices.With that I will turn the call back over to Mayo for concluding comments.

41

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

2009E 2010E 2011E 2012E 2013E

41

2009 & Beyond Forecast

• 2009 expected guidance range of $2.90 to $3.20 remains consistent with December communication • 2010 expected earnings range is $3.05 to $3.45 per share, but includes assumptions related to the

assignment of hedges to the Nuclear JV that may change as the terms of the transaction are finalized• Out year earnings are sensitive to the impact of power and fuel price variability

Adj

uste

d EP

S (1

)

($ per share)

$3.05 - $3.45$2.90 - $3.20

2011 2012 2013

EPS Impact of $1.00 Power Price Exposure (3)

$0.00 $0.03 $0.02

EPS Impact of $1.00 Dark Spread Exposure (2)

$0.05 $0.05 $0.05

EPS Impact of 0.1x Heat Rate Exposure (3)

$0.02 $0.02 $0.01

(1) Data excludes Special Items and UniStar earnings(2) MWhs exposure to Dark Spread assumed to be forecasted generation for coal-burning fleet(3) EPS exposure assumes EDF as a business partner for 50% of the nuclear fleetSee Appendix

42

Concluding Remarks

Mayo A. ShattuckChairman, President and Chief Executive Officer

Constellation Energy

43

Before turning it over for questions, let me take a moment to summarize the investment thesis in Constellation.First, although 2009 will be a transitional year for us, beginning in 2010 and beyond, we have a very attractive fleet of low-cost, environmentally advantage generating assets located primarily in PJM and New York. As we move forward, the profitability of this fleet is expected to increase as we see many of the below-market hedges roll off, potentially accelerated in the near term by hedges that may be allocated to the joint venture with EDF. Second, is our regulated utility. The Maryland PSC is committed to the implementation of efficiency and conservation projects as well as improving system reliability. We will work with the Commission to move these initiatives forward and will deploy incremental capital, provided that the returns support the investment.Third, is our retail and wholesale businesses. We will be moving towards smaller, higher return business sized relative to owned and contracted physical generation. Although this new strategy will decrease our overall volumes, we will continue to include our costs of capital in the price we offer customers. What you will see is an overall reduction in the capital needed to support this business and much higher returns.Finally, we have made the management changes we feel were needed to help drive our new strategy and strengthen our company going forward. We will be adjusting our reporting framework so that our reporting is more closely aligned to our activities. This will lead to greater transparency and will make us more accountable to you as you will now have a better and clearer understand of how we manage each of our businesses.So finally, I would like to add that over the past year it was nearly impossible to be a business leader anywhere in America without feeling humbled, and I feel that sense of humility very much myself. As CEO I take full responsibility for what has occurred at Constellation and for the steps we have taken and will take as we weather this storm. At my request and with the consent of the Constellation board of directors, I am foregoing any bonus for 2008. Please take this as a modest but firm signal that I will do all that I can do to help steer this great Company back to health with renewed growth. We have made some significant strides in the past five months but as we've discussed today, much remains to accomplish. With this leadership team we have reaffirmed the foundation of discipline, execution, and accountability. I believe we are on the right path. Even given this current economic environment, I am also admittedly optimistic that we have a workable solution to our balance sheet issues, that we have a strong international strategic partner, that we have strategically important businesses with committed employees, and that we have the means to earn back your trust and earn the right to grow. We are determined to make progress on that path every day.And now we'll be happy to answer your questions.

43

Summary• Attractive generation assets

– Low-cost, environmentally advantaged fleet – Located primarily in PJM and New York– Roll-off of below market hedges

• Opportunities for increased earnings profile at BGE– MD PSC interest in implementing efficiency and conservation projects– Investment opportunities related to improving system reliability

• Leading retail and wholesale customer businesses– Focused in markets where the company has owned and contracted physical

generation– Continue to include cost of capital in pricing decisions

• Strong, focused management team executing Constellation’s new strategy– Adjusting reporting structure will lead to increased transparency and

accountability

Once the company completes its near-term strategic objectives in 2009, Constellation will be well positioned to take advantage of future growth opportunities

44

Additional Modeling

45

45

Additional Modeling• CEG Financial Results

– Reconciliation from GAAP to Adjusted EPS p. 46

– 2008 Special Items p. 48

– BGE – 2008 Income Statements p. 49

– Merchant Income Statements p. 51

– Customer Supply Gross Margin p. 53

– Global Commodities p. 54

– Cash Flow 2008 p. 55

– Balance Sheet Metrics p. 56

– Pro Forma Balance Sheet Effect of EDF Transaction p. 57

– Historical Net Available Liquidity p. 58

– Derivative Assets & Liabilities p. 59

– Mark-to-Market Derivative Assets p. 61

– Mark-to-Market Results p. 62

– Bank Facilities p. 63

– Credit Default Swap Spreads p. 64

• Credit Quality

• CEG Financial Outlook

• BGE

• Generation

• Customer Supply

• Global Commodities

46

This chart summarizes the reconciliation of GAAP earnings to adjusted earnings per share for the last

three years.

For the full year 2006, GAAP earnings were $5.16 per share. In December 2006, we sold six gas-

fired power plants. The High Desert plant, which distinctly served the California market, was classified

as discontinued operations. The remaining 5 plants, which were part of our operations in other

markets, were not classified as discontinued operations. The (14¢) of Special Items in 2006 includes

the gain on sale of the 5 plants other than High Desert of 26¢, workforce reduction costs of (9¢), and

merger-related costs of (3¢). High Desert operating earnings and the gain on sale, totaling $1.04 per

share, were reclassified to discontinued operations under FAS144. We also excluded from GAAP

EPS a gain of 21 ¢ on non-qualifying hedges and earnings of 16 ¢ on our synfuel plants to arrive at

adjusted EPS of $3.61.

For the full year 2007, GAAP earnings were $4.50 per share. To arrive at adjusted EPS, we first adjust

for 8 ¢ per share of special items, which include the windfarm asset impairment of 7 ¢ and 1 ¢ of

workforce reduction costs. Discontinued Operations of 1¢ related to final adjustments of the sales of

High Desert and Puna, and there was a gain of 1 cent on non-qualifying hedges. The final adjustment

is to exclude a 2 ¢ loss from synfuel operations to arrive at adjusted EPS of $4.60 per share.

For the full year 2008, GAAP earnings were ($7.34) per share. To arrive at adjusted EPS, we first

adjust for $10.54 in special items, which are listed in detail in the next two slides, and add back to

GAAP EPS a loss of 39¢ on non-qualifying hedges. The final adjustment is to add a 2¢ gain from

synfuel operations to arrive at adjusted EPS of $3.57 per share.

46

Full Year Reconciliation from GAAP to Adjusted EPS

($ per share) 2006 2007 2008

GAAP EPS $5.16 $4.50 ($7.34)

Special Items (0.14) 0.08 10.54

Discontinued Operations (1.04) 0.01 0.00

Non-Qualifying Hedges (0.21) (0.01) 0.39

Synfuel Earnings (0.16) 0.02 (0.02)

Adjusted EPS $3.61 $4.60 $3.57

47

47

Quarterly Reconciliation from GAAP to Adjusted EPS

2008

($ per share) Q1 Q2 Q3 Q4

GAAP EPS $0.81 $0.95 ($1.27) ($7.75)

Special Items (0.04) 0.69 2.10 7.71

Discontinued Operations 0.00 0.00 0.00 0.00

Non-Qualifying Hedges 0.19 0.19 (0.07) 0.07

Synfuel Earnings (0.01) (0.01) 0.00 0.00

Adjusted EPS $0.95 $1.82 $0.76 $0.03

2007

Q1 Q2 Q3 Q4

GAAP EPS $1.07 $0.64 $1.38 $1.42

Special Items - 0.08 - -

Discontinued Operations 0.01 - (0.01) -

Non-Qualifying Hedges 0.05 (0.01) (0.01) (0.05)

Synfuel Earnings (0.10) (0.07) 0.09 0.11

Adjusted EPS $1.03 $0.64 $1.45 $1.48

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

This chart details the quarterly reconciliation of GAAP EPS to adjusted

EPS for 2007 and 2008.

2007 items were discussed on the prior slide, and 2008 Items are

discussed in more detail on the next slide.

48

Full year 2008 special items were a loss of ($10.54). In the first quarter, we had a 4¢ favorable special item at

BGE related to the full year tax impact of the $189 million customer credit that was accrued in the second

quarter. The credit caused a reduction in full year effective tax rate, and so in each quarter of 2008, the impact

of the lower effective tax rate on normal earnings was classified as a special item.

In the second quarter, we recorded a negative 69 cent item related to the $188 million customer credit that was

accrued in April. The impact of the credit itself was (70¢), but was partially offset by 1¢ of tax rate impact.

In the third quarter, a variety of items netted to a loss of ($2.10). We recognized ($1.76) in impairment charges

and other costs related to Merchant goodwill, our upstream gas properties, our ownership in CEP, Nuclear

Decommissioning Trust Fund Earnings, and the settlement of fly ash environmental litigation. We had an after-

tax charge of (21¢) due to merger costs, which consisted primarily of the analysis of strategic alternatives and

the pursuit of the MidAmerican transaction. The BGE settlement tax impact was 1¢, and other items, including a

write-down of emissions allowance inventory partially offset by MTM emissions derivative gains related to the

vacation of CAIR and workforce reduction costs, netted to (14¢).

In the fourth quarter, special items netted to ($7.71), driven by an after-tax charge of ($6.43) related to merger

and strategic alternative costs, primarily related to the termination of the MidAmerican deal, the conversion of the

MidAmerican preferred and the pursuit of the EDF transaction. We had further impairments to Merchant

Goodwill, our upstream gas properties, our ownership in CEP, Nuclear Decommissioning Trust Fund Earnings,

and our investment in Nufcor of ($1.27). The BGE Settlement impact was 2¢, and other items, including updates

to the CAIR Impairment and additional workforce reduction costs netted to (3¢).

4848

2008 Special Items($ per share)

Special Items Q1 Q2 Q3 Q4 2008Upstream Gas Asset Impairment $0.00 $0.00 ($0.49) ($0.65) ($1.14)

Goodwill Impairment 0.00 0.00 (0.94) (0.01) (0.96)

Impairment of Equity in CEP 0.00 0.00 (0.19) (0.24) (0.43)

Nuclear Decommissioning Trust Fund Impairment 0.00 0.00 (0.09) (0.33) (0.42)

Other Impairment Losses & Other Costs 0.00 0.00 (0.05) (0.04) (0.09)

Total Impairment Losses & Other Costs $0.00 $0.00 ($1.76) ($1.27) ($3.04)

Merger Related Costs 0.00 0.00 (0.21) (6.43) (6.72)

BGE Settlement 0.04 (0.69) 0.01 0.02 (0.62)

Other 0.00 0.00 (0.14) (0.03) (0.16)

Total Special Items $0.04 ($0.69) ($2.10) ($7.71) ($10.54)

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

49

Baltimore Gas and Electric (BGE) reported adjusted earnings of 85 cents for the full year of

2008, as compared to 74 cents per share in 2007. BGE’s results for the full year 2008 were

positively affected due to benefits from the Maryland settlement. Higher bad debt and higher

interest expense were offset by a variety of favorable items.

Looking at the Income Statement detail:

Gross Margin was favorable by $40M primarily due to the reinstatement of the Provide-of-

Last-Resort (POLR) return under the Maryland settlement, and higher Transmission, Gas,

and Demand Response revenues.

O&M was essentially flat year to year. Higher bad debt expense was offset by a variety of

favorable items.

Depreciation was favorable $3M primarily due to the lower depreciation rates implemented

under the Maryland settlement, partially offset by the impact of higher capital investment.

Higher capital investment also drove higher Allowance for Funds Used During Construction

(AFUDC) which causes the favorable variance in Other Expenses

Interest Expense is higher primarily due to higher long term debt outstanding which is

caused, in part, by the higher capital investment.

49

BGE – 2008 Income Statement

(1) 2007 costs have been reclassified to conform to current year presentationNote: Numbers may not sum due to roundingSee Appendix

($ in millions except per share data) Change2008 2007(1) $ %

Electric Gross Margin 989 955 33 3%

Gas Gross Margin 330 323 7 2%

Gross Margin 1,318 1,278 40 3%

O & M (540) (539) (1) 0%

D & A (228) (234) 6 3%

Other Expenses (166) (169) 3 3%

EBIT 385 337 48 14%

Net Interest Expense (121) (101) (20) (20%)

Income Tax (98) (88) (10) (12%)

Preferred Dividends (13) (13) (0) 0%

Net Income $153 $135 $18 13%

Adjusted EPS $0.85 $0.74 $0.11 15%

Special Items (0.64) (0.05) (0.59) NM

GAAP EPS $0.21 $0.69 ($0.48) (70%)

50

For the fourth quarter of 2008, BGE reported adjusted earnings of 23 cents per share,

compared to adjusted earnings of 17 cents in the fourth quarter of 2007. BGE’s

performance in the fourth quarter of 2008 was positively affected due to benefits from the

Maryland settlement and lower operating and maintenance costs, partially offset by lower

electric distribution revenues due to milder weather and weaker economic conditions, higher

bad debt, and higher interest expense.

Looking at the Income Statement detail:

Gross Margin was favorable by $3M primarily due to the reinstatement of the Provide-of-

Last-Resort (POLR) return under the Maryland settlement, and higher Gas and Demand

Response revenues, partially offset by lower distribution revenues due to milder weather

and weaker economic conditions.

O&M was favorable $18M primarily due to lower employee and other costs, partially offset

by higher bad debt expense.

Depreciation was favorable $2M primarily due to the lower depreciation rates implemented

under the Maryland settlement, partially offset by the impact of higher capital investment.

Interest Expense is higher primarily due to higher long term debt outstanding which is

caused, in part, by the higher capital investment.

50

BGE – Q4 2008 Income Statement

(1) 2007 costs have been reclassified to conform to current year presentationNote: Numbers may not sum due to roundingSee Appendix

($ in millions except per share data) ChangeQ4 2008 Q4 2007(1) $ %

Electric Gross Margin 236 236 0 0%

Gas Gross Margin 95 92 3 3%

Gross Margin 330 327 3 1%

O & M (128) (146) 18 12%

D & A (57) (58) 2 3%

Other Expenses (41) (41) 0 0%

EBIT 104 82 22 27%

Net Interest Expense (33) (28) (5) (19%)

Income Tax (25) (20) (5) (26%)

Preferred Dividends (3) (3) (0) 0%

Net Income $42 $31 $12 38%

Adjusted EPS $0.23 $0.17 $0.06 35%

Special Items 0.06 (0.05) 0.11 NM

GAAP EPS $0.29 $0.12 ($0.17) (142%)

51

Overall, Merchant gross margin decreased by ($206) million from 2007 to

2008. Global Commodities unfavorable gross margin was primarily due to

lower new business. Mid-Atlantic Fleet gross margin was favorable due to the

roll-off of below market hedges. Customer Supply unfavorable gross margin

primarily driven by lower rates and volumes at Retail Power.

Expenses were unfavorable ($10) million driven mainly by our generation

fleet. The main drivers of the generation expense increase over 2007 was

Ash Placement and Coal Handling Costs, Outage costs at Brandon, Wagner,

Crane, Keystone, Conemaugh, the Ginna 2008 RFO, and Nine Mile Point's

year over year RFO's are the main drivers. These costs were partially offset

by lower employee related costs.

Net Interest was unfavorable ($114M) due to lower cash balances, the impact

of the MidAmerican Preferred Dividend, financing expenses, and the 2008

debt issuances

In the end, Merchant net income was unfavorable ($205) million.

51

Merchant – 2008 Income StatementChange

($ in millions except per share data) 2008 (1) 2007 (1) $ %Generation 1,924 1,679 245 15%

Customer Supply 688 801 (113) (14)

Global Commodities 418 756 (338) (45)

Gross Margin 3,030 3,236 (206) (6)Operating & Maintenance (1,685) (1,713) 28 (2)Depreciation & Amortization (285) (250) (35) 14Asset Retirement Obligation (68) (68) (0) 0Other Revenue and Expenses (27) (24) (3) 14

Total Costs below Gross Margin (2,065) (2,055) (10) 1

EBIT 965 1,181 (216) (18)Net Interest Expense (174) (60) (114) (189)

Pre-Tax Income 790 1,121 (330) (30)Income Tax (308) (433) 125 29

Net Income 482 687 (205) (30%)Adjusted EPS 2.69 3.77 (1.08) (29%)Special Items & Non-Qualifying Hedges (10.27) (0.05) (10.22) NMGAAP EPS (7.58) 3.72 (11.30) NM(1) Earnings Exclude special items, certain economic, non-qualifying hedges, and synfuel earningsNote: Numbers may not sum due to rounding See Appendix

52

Overall, Merchant gross margin decreased by ($369) million from Q4 2007 vs

Q4 2008. Global Commodities unfavorable gross margin was the primary

driver due to lower new business. Mid-Atlantic Fleet gross margin was

favorable due to the roll-off of below market hedges. Customer Supply

unfavorable gross margin driven mainly by lower rates and volumes at Retail

Power.

Expenses were favorable $3 million.

Net Interest was unfavorable ($60M) due to lower cash balances, the impact

of the MidAmerican Preferred Dividend, financing expenses, and the 2008

debt issuances

In the end, Merchant net income was unfavorable ($274) million.

52

Merchant – Q4 2008 Income StatementChange

($ in millions except per share data) Q4 2008 (1) Q4 2007 (2) $ %Generation 447 368 79 21%

Customer Supply 209 317 (108) (34)

Global Commodities (109) 231 (340) (147)

Gross Margin 548 917 (369) (40)Operating & Maintenance (419) (434) 15 (3)Depreciation & Amortization (79) (70) (10) 14Asset Retirement Obligation (18) (16) (1) 8Other Revenue and Expenses (2) (1) (2) 316

Total Costs below Gross Margin (518) (521) 3 (1)

EBIT 30 396 (367) (93)Net Interest Expense (78) (17) (60) (347)

Pre-Tax Income (48) 379 (427) (113)Income Tax 7 (146) 153 105

Net Income (41) 233 (274) (118%)Adjusted EPS (0.22) 1.27 (1.49) (117%)Special Items & Non-Qualifying Hedges (7.84) (0.01) (7.83) NMGAAP EPS (8.06) 1.26 (9.32) NM(1) Earnings Exclude special items, certain economic, non-qualifying hedges(2) Earnings Exclude special items, certain economic, non-qualifying hedges, and synfuel earningsNote: Numbers may not sum due to rounding See Appendix

53

53

$0.00$1.00$2.00$3.00$4.00$5.00$6.00$7.00$8.00$9.00

$10.00

4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q080%

20%

40%

60%

80%

100%

Electric Gross Margin Realized / MWh Retention Rates (inc. month-to-month)

Customer Supply Gross Margin($ in millions) FY 2008 FY 2007 Change

Already Originated Business 633

New Business 55

Gross Margin 688 801

Changes in Business Measurement

Wholesale Variable Load Cost (1) (39)

Retail Power Adjustments 0 0

Comparable Gross Margin Results 649 801 (19%)

Full Year Plan 737 800 (8%)

(1) Recognized in Portfolio Management and Trading in prior periods(2) Does not include mark-to-market resultsSee Appendix

Retail GasRetail Power

Retention R

ate

Retention R

ate

Realized As Priced

Elec

tric

GM

/MW

h

Gas

GM

/Dth

(2)

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q0850%

60%

70%

80%

90%

100%

Gross Margin/Dth Retention Rates

As you see in the chart at the top of the slide, during the year, Customer Supply

realized gross margin of $688 million. Year over year, on a comparable basis,

gross margin is down $152 million or 19 percent. The difference is primarily

driven by lower rates in Retail Power as well as lower backlog in Wholesale

Power, partially offset by the acquisition of Cornerstone Energy in Retail Gas.

The Retail Power retention rate was 78 percent in 2008, which is slightly ahead of

last year’s retention rate of 76 percent. Retail Gas’ retention rate was 90 percent

in 2008, which was slightly lower than our 2007 retention rate of 94 percent.

54

54

Global Commodities

($ in millions) Change

FY 2008 FY 2007 $ %

Already Originated Business (1) 292 136 156 NM

New Business Realized (2) (14) 506 (520) NM

Total Contribution Margin (2) 278 642 (364)

(1) Includes Structured Products gross margin originated in prior periods(2) Includes Structured Products, gas (non-project), and coal gross margin and gas project margin (project revenue less operating, depreciation, depletion

and interest expenses incurred at the project level). Excluding gas project-level expenses of ($141) million in 2008 and ($114) million in 2007, total Global Commodities gross margin in 2008 and 2007 was $418 million and $756 million, respectively.

Note: Numbers may not sum due to roundingSee Appendix

Global Commodities Already Originated Business increased 2007 to 2008 by

$156M

New Business Realized decreased by ($520) million mainly driven by Power

Trading results, partially offset by Structured Products. This shortfall was

amplified by our derisking activities which we undertook in Q4 2008.

5555

55

Cash Flow 2008

(1) Items are not allocated to the business segments because they are managed for the company as a whole.Note: Subject to change pending filing of 2008 Form 10-K

Segment Cash Flows($ in millions) Merchant Regulated Operating Activities

Net (loss) income ($1,357) $38 $5 ($1,314)Non-cash merger termination and strategic alternatives costs 542 0 0 542Non-cash adjustments to net (loss) income 817 334 48 1,199Changes in working capital (1,710) (45) 69 (1,685)Defined benefit obligations (1) (5) (15) (1) (21)Other (6) (35) 46 5

Net cash (used in) provided by operating activities (1,715) 292 169 (1,274)Investing Activities

Investments in property, plant and equipment (1,425) (422) (88) (1,934)Asset acquisitions and business combinations, net of cash

acquired (310) - (6) (315)Investment in nuclear decommissioning trust fund securities (441) - - (441)Proceeds from nuclear decommissioning trust fund securities 422 - - 422Sales of investments and other assets 432 13 1 446Decrease (increase) in restricted funds (17) 15 (942) (943)Other investments 23 - (2) 22

Net cash used in investing activities (1,315) (393) (1,035) (2,743)Cash flows from operating activities less cash flows

from investing activities ($3,029) ($101) ($866) ($4,017)Financing Activities (1)

545 420 2,483 3,448Debt issuance costs (85) (2) (18) (105)Proceeds from issuance of common stock (52) 0 69 18Common stock dividends paid 0 (0) (336) (336)Reacquisition of common stock 0 0 (16) (16)Other 161 (172) 126 115

Net cash provided by financing activities 569 246 2,309 3,123Net increase (decrease) in cash and cash equivalents ($3,002) $130 $1,983 ($894)

Holding Company and Other Consolidated

Net issuance (repayment) of debt (includes $1 billion proceedsfrom MidAmerican and $1 billion proceeds from EDF)

This slide shows our 2008 cash flow broken into our Merchant and Regulated

business segments, and for the Holding Company and Other.

Our net cash flow for the year was a use of $0.9 billion. This consisted of cash

flow from operating activities less investing activities of ($4.0) billion, offset by

cash received from financing activities of $3.1 billion.

When looking at the specific segments, the Merchant business had cash flow

from operating activities less investing activities of ($3.0) billion, driven mostly

by a ($1.7) billion change in working capital and a net $1.3 billion used in

investing activities.

Our Regulated business had cash flow from operating activities less investing

activities of ($0.1) billion, due to $0.4 billion used in investing activities,

partially offset by total operating cash flows of $0.3 billion.

In Other, we see the $1.0 billion allocation of restricted cash earmarked for

the January ’09 paydown of the 14% MidAmerican note in the investing

activities.

56

56

Balance Sheet Metrics

($ in billions) 12/31/07 12/31/08DebtTotal Adjusted Debt $4.9 $6.7

Capital50% Hybrid & Preferred Securities 0.1 0.9

Equity (1) 5.5 3.4

Total Capital 10.6 11.0

FFO (2) 1.4 0.5

Imputed Debt (3) 3.3 3.2

(1) Based on our assumption of the S&P methodology and excluding special items(2) Based on our assumptions of the S&P methodology for FFO computation excluding all Special Items(3) Based on S&P’s methodology for calculating imputed debtNote: Numbers may not add due to roundingSee Appendix

(1)

Increases in debt in 2008 were driven by the roughly $850 million of

incremental short-term borrowings, a $400 million note issued by BGE, the

$250 million zero-coupon note issued in July, and the $450M retail hybrid also

issued in July. These increases were slightly offset by principal repayments

and debt maturities of just over $450 million for the year.

The hybrid securities are treated as 50% equity by the ratings agencies,

driving only a $225 million increase in debt year over year.

Realized losses in 2008 negatively impacted both retained earnings and total

capitalization. This was primarily driven by charges associated with the

MidAmerican merger termination.

We estimate the company had approximately $3.2 billion of imputed debt for

year-end 2008 as compared to $3.3 billion at the end of 2007. The primary

driver of this decrease was the roll-off of contracts which make up imputed

debt.

57

57

Pro Forma Balance Sheet Effect of EDF Transaction

($ in billions)Prior to

Termination

MEHCTermination/

EdF Pfd.Actual

12/31/08MEHC Notes

EdFClose

Post Close

Cash 0.8 (0.6) 0.2 - 2.1 2.3

CENG assets 4.2 - 4.2 - (4.2) -

Investment in CENG - - - - 4.5 4.5

Other assets 16.8 1.0 17.8 (1.0) - 16.8

Total Assets 21.8 0.4 22.2 (1.0) 2.4 23.6

MEHC and EdF debt 1.0 1.0 2.0 (1.0) (1.0) -

CENG liabilities 1.7 - 1.7 - (1.7) -

Other liabilities 10.2 - 10.2 - 1.5 11.7

Long-term debt 5.1 - 5.1 - - 5.1

Total Liabilities 18.0 1.0 19.0 (1.0) (1.2) 16.8

Total Equity 3.8 (0.6) 3.2 (0.0) 3.6 6.8

The EDF transaction also offers immediate and significant restoration

to the balance sheet. The significant non-cash impact to equity of the

MidAmerican break-up, which flowed through our P&L in 2008, is more

than restored with the EDF transaction. Our book value under this

transaction increases to $6.8 billion, as seen here, and our capital

ratios improve significantly. Upon completion, the transaction’s

purchase accounting releases the hidden value of our nuclear assets

and right sizes their contribution to the assets on our balance sheet. It

also provides greater transparency to the inherent value of the

company.

58

58

Historical Net Available Liquidity

(1) Includes letters of credit posted under uncommitted facilities(2) Does not include $1 billion earmarked for repayment of MEHC note as of 12/31/08Numbers may not add due to rounding.Note: Subject to change pending filing of 2008 Form 10-K

($ billions) 12/31/07 3/31/08 6/30/08 9/30/08 12/31/08

Credit facilities $4.50 $5.00 $6.13 $6.13 $6.58

Less: Letters of credit issued (1) (1.81) (2.58) (4.33) (3.98) (3.56)

Less: Cash drawn on credit facilities - - - (0.75) (0.87)

Undrawn facilities 2.69 2.42 1.80 1.40 2.15

Less: Commercial paper outstanding - - (0.15) (0.50) -

Net available facilities 2.69 2.42 1.65 0.90 2.15

Add: Cash (2) 1.10 0.66 1.23 1.43 0.20

Net available liquidity $3.79 $3.08 $2.88 $2.33 $2.35

This table shows the breakdown of our Net Available Liquidity by quarter

over the past year. Net Available Liquidity decreased year over year

from $3.79 billion to $2.35 billion. While total available credit facilities

increased from $4.50 billion in December 2007 to $6.58 billion in

December 2008, this was offset by $0.87 billion in total draws on those

facilities and a $1.75 billion increase in letters of credit issued. This

resulted in a net decrease in net available facilities of $0.54 billion year

over year.

Additionally, over the course of the year, cash balances decreased from

$1.10 billion to $0.20 billion. Note that this does not include the $1 billion

restricted cash reserved for the January 09 repayment of the 14%

MidAmerican note.

59

59

Derivative Assets and Liabilities($ millions) 12/31/08 12/31/07

Current Assets $1,465.0 $760.6

Noncurrent Assets 851.8 1,030.2

Total Assets 2,316.8 1,790.8

Current Liabilities 1,241.8 1,134.3

Noncurrent Liabilities 1,115.0 1,118.9

Total Liabilities 2,356.8 2,253.2

Net Derivative Position $(40.0) $(462.4)

Composition of Net Derivative Position:

Hedges $(1,837.6) $(937.6)

Mark-to-Market 1,485.9 673.0

Net cash collateral included in derivative balances 311.7 (197.8)

Net Derivative Position $(40.0) $(462.4)

Note: Subject to change pending filing of 2008 Form 10-K

Our “Derivative assets and liabilities” include contracts accounted for as

hedges and those accounted for on a mark-to-market basis. The

amounts are presented in our Consolidated Balance Sheets after the

impact of netting as required by FSP FIN 39-1. Due to the impacts of

commodity prices, the number of open positions, master netting

arrangements, and offsetting risk positions on the presentation of our

derivative assets and liabilities in our Consolidated Balance Sheets, we

believe an evaluation of the net position is the most relevant measure,

and is discussed in more detail below.

The increase of $900.0 million in our net derivative liability subject to

hedge accounting since December 31, 2007 was due primarily to $1,232

million of losses associated with existing hedge positions due to

unfavorable price changes. These losses were partially offset by $332

million related to the settlement of out-of-the-money cash-flow hedges

during 2008.

60

60

Derivative Assets and Liabilities

Derivative Assets and Liabilities($ millions at 12/31/08) Level 1 Level 2 Level 3

Netting / Collateral (4)

Total Net Fair Value

Cash equivalents $ 928.5 $ -- $ -- $ -- $ 928.5

Debt and Equity Securities 305.4 764.1 -- -- 1,069.5

Derivative Assets 1,565.2 45,499.3 4,793.6 (50,785.9) 1,072.2

Derivative Liabilities (1,728.7) (46,969.1) (4,756.6) 51,097.6 (2,356.8)

Net Derivative Position (163.5) (1,469.8) 37.0 311.7 (1,284.6)

Total $ 1,070.4 $ (705.7) $ 37.0 $ 311.7 $ 713.4(1) Debt and equity securities represent available-for-sale investments which are included in “Nuclear decommissioning trust funds” and “Other assets” in the Consolidated Balance Sheets.(2) Derivative instruments represent unrealized amounts related to all derivative positions, including futures, forwards, swaps, and options. (3) Represents the unrealized fair value of exchange traded derivatives excluding cash margin posted. We classify exchange-listed contracts, which are settled in cash on a daily basis, as part of

“Accounts Receivable” in our Consolidated Balance Sheets.(4) We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable

master netting agreement exists between us and the counterparty to a derivative contract. At December 31, 2008, we included $223.0 million of cash collateral held and $534.7 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts.

($ millions) Assets as of 12/31/08 Liabilities as of 12/31/08

Cash equivalents $ 928.5 $ --

Debt and equity securities (1) 1,069.5 --

Derivative instruments: (2)

Classified as derivative assets and liabilities:

Current 1,465.0 (1,241.8)

Noncurrent 851.8 (1,115.0)

Total Classified as derivative assets and liabilities 2,316.8 (2,356.8)

Classified as accounts receivable (3) (1,244.6) --

Total derivative instruments 1,072.2 (2,356.8)

Total recurring fair value measurements $ 3,070.2 $ (2,356.8)

Note: Subject to change pending filing of 2008 Form 10-K

Cash equivalents represent money market mutual funds which are included in "Cash and cash equivalents" and

“Restricted cash” in the Consolidated Balance Sheets. Debt and equity securities represent available-for-sale

investments which are included in "Nuclear decommissioning trust funds" and "Other assets" in the Consolidated

Balance Sheets. Derivative instruments represent unrealized amounts related to all derivative positions, including

futures, forwards, swaps, and options. We classify exchange-listed contracts as part of "Accounts Receivable" in

our Consolidated Balance Sheets. We classify the remainder of our derivative contracts as "Derivative assets" or

"Derivative liabilities" in our Consolidated Balance Sheets.

The second table on this slide disaggregates our net derivative assets and liabilities on a gross contract-by-

contract basis as required by SFAS No. 157. A primary focus of SFAS No. 157 is the fair value hierarchy that

provides information about how fair value measurements are determined. SFAS No. 157 requires each individual

asset or liability that is remeasured at fair value on a recurring basis to be presented in this table and classified,

in its entirety, within the appropriate level in the fair value hierarchy. Therefore, the objective of this table is to

provide information about how each individual derivative contract is valued within the fair value hierarchy,

regardless of whether a particular contract is eligible for netting against other contracts or whether it has been

collateralized. Because contracts with the same counterparty could fall into multiple levels within the fair value

hierarchy, it is necessary to make this gross presentation in order to classify entire contracts into the appropriate

level as required by SFAS No. 157. However, these gross balances are not indicative of either our actual credit

exposure or net economic exposure since they do not reflect legally enforceable master netting agreements or

cash or other forms of collateral, nor do they reflect the extent to which offsetting derivative and nonderivative

positions or the capacity of physical assets reduce our economic exposure to risk. These gross balances are

intended solely to provide information on sources of inputs to fair value and proportions of fair value involving

objective versus subjective valuations.

61

61

Mark-to-Market Derivative AssetsDerivative Assets Subject to Mark-to-Market Accounting

Settlement Term

($ millions at 12/31/08) 2009 2010 2011 2012 2013 2014 Thereafter Fair Value

Level 1 $ (19.9) $ -- $ -- $ -- $ -- $ -- $ -- $ (19.9)

Level 2 520.0 (45.8) 196.8 99.9 (16.1) (0.4) (0.6) 753.8

Level 3 312.7 343.9 147.4 (38.8) (11.2) 2.9 (4.9) 752.0

Total net derivative asset subject to MTM accounting $ 812.8 $ 298.1 $ 344.2 $ 61.1 $ (27.3) $ 2.5 $ (5.5) $ 1,485.9

Change in Net MTM Derivative Assets ($ in millions) Quarter Ended 12/31/08 Twelve Months Ended 12/31/08

Fair value beginning of period $ 1,559.8 $ 673.0

Origination gains -- 73.8

Unrealized changes in fair value (83.3) 159.8

Changes in valuation techniques -- --

Reclassification of settled contracts to realized (93.0) 48.2

Total changes in fair value recorded in earnings (176.3) 281.8

Changes in value of exchange-listed futures and options 152.6 571.3

Net change in premiums on options (56.0) 19.2

Contracts acquired -- --

Other changes in fair value 5.8 (59.4)

Fair value at end of period $ 1,485.9 $ 1,485.9

Note: Subject to change pending filing of 2008 Form 10-K

Changes in our net derivative asset subject to mark-to-market accounting that affected earnings were as follows:

• Origination gains represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by applicable accounting rules.

• Unrealized changes in fair value represent unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.

• Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements used to value our portfolio to more accurately reflect the economic value of our contracts.

• Reclassification of settled contracts to realized represents the portion of previously unrealized amounts settled during the period and recorded as realized revenues.

The net mark-to-market derivative asset also changed due to the following items recorded in accounts other than in our Consolidated Statements of Income (Loss):

• Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in nonregulatedrevenues. The fair value of these contracts is recorded in “Accounts receivable” rather than “Derivative assets” in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.

• Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net derivative asset and premiums on options sold as a decrease in the net derivative asset.

• Contracts acquired represents the initial fair value of acquired derivative contracts recorded in “Derivative assets and liabilities” in our Consolidated Balance Sheets.

• Other changes in fair value include transfers of derivative assets and liabilities between accounting methods resulting from the designation and de-designation of cash-flow hedges.

62

Total mark-to-market results decreased $309.1 million during the year ended December 31, 2008 compared to the same period of 2007 primarily due to unrealized changes in fair value. The period-to-period variance in unrealized changes in fair value was primarily due to lower gains from unrealized changes in fair value of $341.0 million from risk management and trading, partially offset by an increase in origination gains of $31.9 million. The net decrease in risk management and trading gains of $341 million was primarily due to:

$619 million of increased losses related to power and transmission in the Northeast, PJM, and ERCOT regions due to unfavorable price movements, execution of transactions to reduce our risk position consistent with changes in our strategy, and execution of those transactions in less liquid market conditions, lower gains of approximately $29 million from our emissions trading activities due primarily to unfavorable price movements, and$104 million of increased losses related to unfavorable price movements on certain economic hedges of accrual transactions, primarily related to gas transportation and storage and freight that do not qualify for or are not designated as cash-flow hedges.

The risk management and trading results were partially offset by:$356 million of gains primarily as a result of favorable price movements relating to mark-to-market derivatives that we de-designated as cash-flow hedges from our international commodities business, and$55 million of gains primarily related to our wholesale and retail gas businesses due to favorable price movements on our sales of wholesale and retail natural gas.

62

Mark-to-Market Results

Quarter Ended Twelve Months Ended($ millions) 12/31/08 12/31/07 12/31/08 12/31/07Unrealized Mark-to-Market Results

Origination gains $ -- $ 4.5 $ 73.8 $ 41.9

Risk management and trading – MTM

Unrealized changes in fair value (83.3) 330.8 159.8 500.8

Changes in valuation techniques -- -- -- --

Reclassification of settled contracts to realized (93.0) (180.1) 48.2 (369.3)

Total risk management and trading – MTM (176.3) 150.7 208.0 131.5

Total unrealized MTM (1) (176.3) 155.2 281.8 173.4

Realized MTM 93.0 180.1 (48.2) 369.3

Total MTM results $ (83.3) $ 335.3 $ 233.6 $ 542.7

(1) Total unrealized mark-to-market is the sum of origination gains and total risk management and trading – mark-to-market.

Note: Subject to change pending filing of 2008 Form 10-K

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63

Bank Facilities

Committed Facilities ($ billions)

12/31/08 Expiration 2009 E Expiration

HoldCo (CE) Syndicated $3.9 July 2012 $2.3 July 2012

Syndicated 1.2 Nov 2009 -

Bilateral 0.5 Dec 2009-Sep 2013 -

EDF interim/put 0.6 June 2009 (1) 1.4 Dec 2010

Subtotal (CE) $6.2 $3.7

Utility (BGE) Syndicated 0.4 Dec 2011 0.4 Dec 2011

Group (CEG) Total (CEG) $6.6 $4.1

Assuming Nuclear JV CloseCurrent

(1) Expires the earlier of June 2009, alternative financing of $600 million, or regulatory approval for the EDF put option

Previously noted: We have a $1.2 billion credit facility which is scheduled to expire in

November 2009. Under its original terms, this credit facility would have been

reduced by $1 billion as a result of the proceeds we received from EDF in exchange

for the 8% Series B Preferred Stock. We have amended this facility so that total

commitments remain at $1.2 billion following our receipt of $1 billion from EDF. This

credit facility will terminate at the earlier of the closing of the membership interest

purchase agreement or the original expiration date of the credit facility in November

2009. We also have three facilities totaling $4.4 billion that lenders would have the

right to terminate following completion of the membership interest purchase. We

have amended our $3.9 billion credit facility so that it will remain in effect following

the closing of the EDF membership interest purchase but at a reduced amount of

$2.3 billion, which would be secured by certain of our assets if our credit rating is

downgraded. The two remaining facilities totaling $0.5 billion would terminate upon

the closing of the EDF transaction.

64

64

Credit Default Swap Spreads

Spre

ad to

LIB

OR

50 bps

150 bps

250 bps

350 bps

450 bps

550 bps

650 bps

1/2/

08

2/16

/08

4/1/

08

5/16

/08

6/30

/08

8/14

/08

9/28

/08

11/1

2/08

12/2

7/08

2/10

/09

CEG 5-Year CDS Investment Grade 5-Year CDS Index

*9/15: Lehman Brothers files for bankruptcy

9/17: S&P places CEG on Watch Developing

9/18: CEG and MEHC announce merger. Moody's downgrades CEG to Baa2. Fitch affirms CEG at BBB

9/22: MEHC completes initial due diligence and invests $1B in CEG

10/2: MEHC completes 14-Day due diligence

12/3: EDF makes unsolicited proposal12/17: CEG and EDF announce definitive investment agreement

This slide presents our 5-year credit default swap spreads (CDS) versus the

investment grade credit default swap spread index from January 2, 2008 to February

12, 2009. Our CDS spreads have narrowed 242bps since the start of 2009.

65

65

Additional Modeling

• CEG Financial Results

• Credit Quality

– Wholesale Portfolio Credit Quality p. 66

– Credit Quality and Exposures p. 67

– Value at Risk p. 68

• CEG Financial Outlook

• BGE

• Generation

• Customer Supply

• Global Commodities

66

66

Wholesale Portfolio Credit Quality

As of December 31, 2008

6%10%

2%3%6%

39%

1%

33%

Domestic Coal International CoalFinancial FreightGas Municipalities/Cooperatives/UtilitiesOthers Power

0%10%20%30%40%50%60%70%80%90%

12/3

1/20

05

12/2

9/20

06

3/30

/200

7

6/30

/200

7

9/30

/200

7

12/3

1/20

07

3/31

/200

8

6/30

/200

8

9/30

/200

8

12/3

1/20

08

% o

f Inv

estm

ent G

rade

Investment Grade Non-Investment Grade

Portfolio Credit Quality Credit Exposure by Sector (Net of Collateral)

Constellation’s exposure to lower credit quality coal producers and merchant power generators has fallen considerably. Conversely, exposures to higher credit quality

load-serving entities (mostly utilities, municipalities, and cooperatives) have increased

Note: Based on internal credit ratings

The Portfolio credit quality chart on the left shows the break up of

investment and non-investment grade break up of our net credit

exposure. As of Dec. 31, 72 percent of the exposure is with investment-

grade counterparties.

The chart on the right shows the Exposure net of collateral by industry

segments.

67

67

Credit Quality and Exposures

Rating

Total Exposure

Before Credit

CollateralCredit

CollateralNet

Exposure

Number of Counterparties Greater than 10% of Net Exposure

Net Exposure of Counterparties

Greater than 10% of Net Exposure

(In millions)

Investment Grade $1,595 $382 $1,213 - -

Split rating $7 - $7 - -

Non-investment grade $255 $53 $202 - -

Internally rated – investment grade $293 $60 $233 - -

Internally rated – non-investment grade $96 $11 $85 - -

Total $2,246 $507 $1,740 - -

Note: Represents net exposure recorded on our balance sheetThere are approximately ten counterparties split between investment and non-investment grade ratingsSubject to change pending filing of 2008 Form 10-K

Our total portfolio exposure related to exposure on the consolidated

financial statements decreased from $2.2 billion to $1.7 billion, quarter

over quarter. No single counterparty concentration made up more than

10% of the total portfolio exposure.

68

68

Value at Risk

Unit VaR decreased in Q4 2008 compared to Q3 2008

Average MTM VaR includes all positions with MTM accounting treatment.

Average trading VaR includes all positions in the GCG proprietary trading portfolio.

05

101520253035

04 Q

104

Q2

04 Q

304

Q4

05 Q

105

Q2

05 Q

305

Q4

06 Q

106

Q2

06 Q

306

Q4

07 Q

107

Q2

07 Q

307

Q4

08 Q

108

Q2

08 Q

308

Q4

$ in

mill

ions

Average of Trading 99% VaRAverage of Trading 95% VaR

05

101520253035

04 Q

104

Q2

04 Q

304

Q4

05 Q

105

Q2

05 Q

305

Q4

06 Q

106

Q2

06 Q

306

Q4

07 Q

107

Q2

07 Q

307

Q4

08 Q

108

Q2

08 Q

308

Q4

$ in

mill

ions

Average of MTM 99% VaRAverage of MTM 95% VaR

Quarterly Average Trading VaR Quarterly Average MTM VaR

The value at risk of our mark to market portfolio decreased in Q4 2008 due to reduction in Unit VaR and portfolio de-risking

Date Nymex GasPJM West

Peak Nymex Coal API2 Coal12/31/07 $ 0.53 $ 4.56 $ 1.60 $ 6.35 03/31/08 $ 0.75 $ 5.27 $ 6.86 $ 8.34 06/30/08 $ 0.83 $ 6.44 $ 7.94 $ 7.99 09/30/08 $ 0.89 $ 7.31 $ 17.97 $ 17.98 12/31/08 $ 0.77 $ 5.20 $ 9.99 $ 15.07

The chart on the left shows quarterly average Value at Risk for our

Trading Portfolio. The chart on the right is the Value at Risk for the Mark-

to-Market portfolio.

The VaR numbers are shown at 95% and 99% confidence levels.

The table on the bottom the unit VaR for major commodities.

The Mark to market VaR in December 2008 excludes the International

coal MTM positions, related to the divestment of the London business.

69

69

Additional Modeling

• CEG Financial Results

• Credit Quality

• CEG Financial Outlook

– 2009E BGE Income Statement p. 70

– Merchant –2009E Income Statement p. 71

– Depreciation and Amortization p. 72

– Merchant – 2009E EBIT p. 73

– 2009E Consolidated Cash Flow p. 74

– Capital Spending - BGE p. 75

– Capital Spending - Merchant p. 76

– Forward Market Prices p. 77

• BGE

• Generation

• Customer Supply

• Global Commodities

70

70

2009E BGE Income Statement($ in millions except per share data) 2009E (1) 2008 ChangeElectric Gross Margin $1,077 $989 88

Gas Gross Margin 327 330 (3)

Gross Margin 1,404 1,318 86O & M (568) (540) (28)

D & A (261) (228) (33)

Other Expenses (173) (166) (7)EBIT 402 385 17

Net Interest Expense (130) (121) (9)

Income Tax (104) (98) (6)

Preferred Dividends (13) (13) (0)

Net Income $155 $153 $3Adjusted EPS (1) $0.77 $0.85 ($0.08)

(1) Represents mid-point of guidance rangeNote: Numbers may not sum due to roundingSee Appendix

Major Variance Drivers vs. 2008• +16¢ Other Electric Distribution Revenue (10¢) Dilution

• +1¢ Tracker Impact (12¢) O&M and Other Expenses

(3¢) Interest Expense

BGE's gross margin is expected to be higher by $86M in 2009 primarily

due to the implementation of currently approved Smart Energy Savers

Programs (Conservation and Demand Respond Initiative) and a variety

of other drivers. Certain Conservation programs that were recently

approved by the Maryland PSC have a 1 year amortization period

and drive the significant increase in depreciation as well as the higher

revenue. Excluding the effect of the conservation program amortization,

D&A will be slightly favorable due to the rates established as part of the

Maryland settlement, partially offset by the impact of higher capital

spending.

O&M costs will be higher primarily due to inflation, including higher

pension expenses. Interest expense will be higher due to higher capital

investment for system reliability and capacity expansion as well as the

growth of Smart Energy Savers Programs.

71

71

Merchant – 2009E Income Statement

(1) Earnings Exclude special items, certain economic, non-qualifying hedges, and synfuel earningsNote: Numbers may not sum due to roundingSee Appendix

Change

($ in millions) 2009E 2008 (1) $ %Generation $1,880 $1,924 $(44) (2)%

Customer Supply 614 688 (74) (11)

Global Commodities 272 418 (146) (35)

Gross Margin 2,766 3,030 (264) (9)Operating & Maintenance (1,386) (1,685) 299 18Depreciation & Amortization (262) (285) 23 8Asset Retirement Obligation (54) (68) 14 21Other Revenue and Expenses (10) (27) 18 64

Total Costs below Gross Margin (1,711) (2,065) 354 17

EBIT 1,055 965 91 9Net Interest Expense (266) (174) (92) (53)

Pre-Tax Income 789 790 (1) 0Income Tax (339) (308) (31) (10)

Net Income $450 $482 (32) (7)

Overall, Merchant gross margin is expected to decrease by ($264) million from 2008

to 2009. Generation is expected to be relatively flat with higher gross margin due to

the roll-off of below-market hedges offset by the impact of the expected GM lost by

the formation of the nuclear joint venture. Customer Supply Gross margin is

expected to be down mainly due to Wholesale Power, partially offset by favorable

results at Retail Gas. Global Commodities gross margin is forecasted to be down

due to the resizing of the business.

Expenses are estimated to be down $354 million due to cost reductions throughout

the company, and the formation of the nuclear joint venture. As previously noted the

Nuclear JV is forecasted to close on 9/30/09 in Q4 09.

Net Interest expense will also be higher due to the EDF Preferred Dividend,

financing expenses, and 2008 debt issuances.

In the end, Merchant net income is expected to be unfavorable ($32) million.

72

7272

Depreciation and Amortization (1)

($ in millions)

2008Actual

2009Plan

2010Plan

2011Plan

2012Plan

Non-Nuclear Generation 71.7 81.6 127.6 139.4 141.4

Nuclear Generation 170.6 182.4 189.8 206.2 225.5

Other Merchant D&A 111.1 97.8 119.1 125.9 115.3

Total Merchant 353.4 361.8 436.5 471.5 482.2

BGE 227.9 260.7 249.2 282.5 311.9

Other Non-Regulated 9.5 11.1 10.6 10.6 10.7

Headquarters 58.7 48.0 37.0 32.4 26.4

Total Fixed Asset D&A 649.5 681.5 733.3 797.1 831.2

Synfuels D&A 2.1 - - - -

Energy Contract Amortization (256.3) (181.9) (183.8) (88.7) (84.8)

Nuclear Fuel Amortization 123.9 137.1 160.1 178.7 203.8

All Other Amortization 40.5 107.0 19.4 20.7 21.3

Total per GAAP Statement of Cash Flows (2) 559.7 743.7 729.0 907.7 971.5

JV Impact - Fixed Asset D&A (46.1) (189.8) (206.2) (225.5)

JV Impact - Nuclear Fuel Amortization (38.0) (160.1) (178.7) (203.8)

Total Post JV 559.7 659.6 379.1 522.9 542.2(1) Fixed asset D&A includes accretion of Asset Retirement Obligations(2) Plan data excludes amortization of the mark-up to fair value of the retained nuclear investment

Full year 2008 fixed asset depreciation and amortization excluding

synfuels and including accretion of asset retirement obligations totaled

$650M. Non-fixed asset amortization primarily includes nuclear fuel and

energy contracts. Other amortization in 2009 is driven by fees relating

to financing.

Accounting treatment of the nuclear joint venture with EDF is expected

to follow the equity method. Therefore, nuclear related depreciation and

amortization will no longer be included in consolidated results. The

expected depreciation and amortization impact of deconsolidating

nuclear operations are reflected on the bottom portion of this slide; 2009

forecasted statements incorporate the expected impact of the joint

venture.

73

73

Merchant – 2009E EBIT

($ in millions) Generation Customer Supply

Global Commodities

Total Merchant

Gross Margin $1,880 $614 $272 $2,766

Less: Operating Expenses (1) (1,195) (321) (195) (1,711)

EBIT 685 292 78 1,055

Add: Depreciation & Amortization 218 23 75 316

EBITDA 903 315 153 1,371

Note: May not add due to rounding(1) Includes upstream gas operating expenses in Global Commodities.Operating Expense includes estimates for Commercial Operations, Marketing, and Headquarter CostsSee Appendix

Total Merchant EBITDA for 2009 is projected to be

approximately $1.4 billion, primarily consisting of $903 million

in Generation, $315 million in Customer Supply, and $153

million in Global Commodities.

74

74

2009E Consolidated Cash Flow

(1) Items are not allocated to the business segments because they are managed for the company as a wholeNumbers may not add due to rounding

Segment Cash Flows($ in billions) Merchant Regulated ConsolidatedOperating Activities

Net income $0.4 $0.2 $ - $0.5Non-cash adjustments to net income 0.3 0.3 0.1 0.7Changes in working capital 1.0 (0.1) - 0.9Defined benefit obligations (1) (0.0) (0.0) (0.1) (0.1)Other 0.1 (0.1) - -

Net cash provided by operating activities 1.7 0.3 0.1 2.0Investing Activities

Investments in property, plant and equipment (1.2) (0.4) - (1.7)Sales of investments and other assets (after-tax) 3.1 - - 3.1Decrease in restricted funds - - 1.0 1.0

Net cash (used in) provided by investing activities 1.9 (0.4) 1.0 2.4Cash flows from operating activities less cash flows

from investing activities $3.6 ($0.1) $1.1 $4.4Financing Activities (1)

Net repayment of debt (includes repayments of $1 billion EDF preferred, $1 billion MEHC note, $500 million 6.125% note, and $1 billion of other debt, and issuance of $250 million) (2.8) 0.2 (0.5) (3.1)Common stock dividends paid 0.0 0.0 (0.2) (0.2)Other 0.1 0.0 0.0 0.1

Net cash used in financing activities (2.8) 0.2 (0.6) (3.2)Net increase in cash and cash equivalents $0.8 $0.1 $0.3 $1.2

Holding Company and Other

This slide shows our projected 2009 cash flow broken out into our Merchant and

Regulated business segments, and for the Holding Company and Other.

For the year, we are forecasting a net cash inflow of $1.2 billion. This consists of free

cash flow of $4.4 billion, offset by a $3.2 billion use of cash due to financing

activities, including the paydown of the $1 billion EDF Series B preferred and $1

billion 14% MidAmerican note.

Looking at the business segments, we expect the Merchant business to realize free

cash flow of $3.6 billion. This is composed of $1.7 billion in operating cash inflow and

$1.9 billion in investing cash inflow, the latter driven primarily by approximately $3.1

billion in after-tax proceeds from the EDF asset sale.

For our Regulated business, we are forecasting free cash flow of ($0.1) billion, driven

by operating cash inflow of $0.3 billion, offset by $0.4 billion spent on PP&E

investments.

In Other, the $1 billion reduction in restricted cash is used to repay the 14%

MidAmerican note.

75

75

Capital Spending - BGE

($ in millions) 2008 2009E 2010E

Baltimore Gas & Electric

Electric / Gas Distribution $350 $311 $464

Electric Transmission 82 53 113

Smart Energy Savers Initiatives 30 88 139

Utility Total $462 $452 $716

• Key drivers of capital expenditures:– Electric and gas infrastructure spending for reliability– Electric transmission investments for reliability– Smart Energy SaversSM initiatives including energy efficiency, demand response and advanced

metering

Prior Plan 493 562 648

Change 31 110 (68)

From 2008 to 2009 BGE capital investment is expected to be flat.

Investments in Smart Energy Savers SM initiatives are expected to

increase while spending associated with the distribution system in the core

business, in light of the economic environment, is expected to decrease.

Looking toward 2010, we expect a gradual return to a normal economic

environment leading to increased investments in the core business and

continued expansion in investments in Smart Energy Savers SM

initiatives.

76

76

Capital Spending - Merchant

($ in millions) 2008(1) 2009E 2010EMajor Environmental $555 $300 $45Maintenance Capital Spending 304 394 340

- Generation (Excluding Major Environmental)

- Other Merchant

Growth 623 370 148- Upstream Gas (E&P) Projects

- Hillabee Plant Acquisition

- West Valley Plant Acquisition

- Nine Mile Point Extended Power Uprate (EPU)

Merchant Capital Expenditures (excluding Nuclear Fuel) 1,482 1,064 533Nuclear Fuel 193 257 211

Total Merchant Capital Expenditures $1,675 $1,321 $744

Note: Numbers may not add due to rounding (1) Numbers exclude Nufcor acquisition $64M

Nuclear JV Capex - 80 429

Merchant Excluding Nuclear JV $1,675 $1,241 $315

Merchant capital expenditures are expected to decrease to $744 million

in 2010 before adjusting for the impact of the nuclear JV. This reduction

is primarily driven by the completion of Hillabee plant construction and

completion of Major Environmental projects. Spending on plant

maintenance is expected to be approximately $300 million to $400

million per year.

Additional new growth investment will be considered in a case by case

basis as opportunities are identified and the careful management of

liquidity permits.

77

77

Forward Market Prices (as of 12/31/08)

2009 2010 2011

NYMEX Gas ($/MMBtu) 5.0 6.6 7.2

NYMEX Coal ($/Ton) 58.0 61.2 64.0

PJM WHUB ($/MWh) (7 x 24) 46.6 54.2 57.3

The above market prices are indicative of the prices used in our outlook.

78

78

Additional Modeling

• CEG Financial Results

• Credit Quality

• CEG Financial Outlook

• BGE

– BGE Overview p. 79

– BGE Gross Margin p. 80

– BGE Electric Delivery Quarterly Profile p. 81

– BGE Gas Delivery Quarterly Profile p. 82

– 2008 BGE Rate Base p. 83

– BGE ROE p. 84

• Generation

• Customer Supply

• Global Commodities

79

79

Baltimore Gas & Electric OverviewBaltimore Gas & Electric (BGE) Service Area – Central Maryland

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

Electric customers (millions) 1.2

Gas customers (millions) 0.65

2008 Rate base ($ billions) $3.5

2008 Net income ($ millions)

Before Special Items $38.2

After Special Items $152.6

ROE 9.4%

Long-term volume growth (customer & usage) 1%

Regulators- Electric & gas distribution- Electric transmission

Maryland PSCFERC

Industry rank per FERC year-end 2007 (by # of customers)

- Electric distribution- Gas distribution

24th

14th

Baltimore Gas & Electric serves 1.2 million electric customers and

650,000 gas customers in central Maryland. In 2008, BGE had a

distribution rate base of approximately $3.1 billion and a transmission

rate base of $0.4 billion, for a total of $3.5 billion. BGE generated

$152.6 million of net income after special items, which translated into a

GAAP ROE of about 9.4%.

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 14th out of 46 companies

with at least 100,000 customers.

80

80

BGE Gross Margin

(1) Adjusted to exclude $170 credit per residential customerSee Appendix

($ in millions) 2009E 2008

Electric Revenue(1) $3,050 $2,869

Gas Revenue 928 1,024

Total Regulated Revenue 3,978 3,892

Electricity Purchased for Resale (1,973) (1,880)

Gas Purchased for Resale (601) (695)

Total Cost of Goods Sold (2,574) (2,575)

Electric Gross Margin 1,077 988

Gas Margin 327 330

Total Gross Margin $1,404 $1,318

In 2009, we expect to generate $4.0 billion in total regulated revenue, an

increase of 2% over 2008. This increase is primarily due to modest

customer growth and recovery of Smart Energy Savers Program costs.

We expect customer growth for 2009 to range from 0.9%-1.4%.

Our cost of goods sold is expected to be approximately $2.6 billion with

electricity purchased for resale increasing 5% primarily due to higher

Standard Offer Service prices. Gas purchased for resale in 2009 is

expected to decrease 13% due to lower natural gas prices.

81

81

BGE Electric Delivery Quarterly Profile

Period CustomersEBITDA (millions)

SOSReturn

2008

Q1 1,229,640 $126 $7.3

Q2 1,229,211 102 6.1

Q3 1,228,882 134 7.5

Q4 1,231,481 115 6.4

Total 2008 $477 $27.3

2009E 1,245,614 $515 $27.6

Excludes Special Items - See Appendix

This slide details our electric delivery profile for 2008 broken down into

quarters and provides an estimate for full year 2009 electric delivery. In

2008, electric delivery contributed $477 million in EBITDA. For 2009,

estimated EBITDA from electric delivery is $515 million.

The Standard Offer Service return is approved by the Maryland PSC. It

is the shareholder return earned by BGE for the risk of administering the

program. The residential return is $1.50 per MWh served. Small

business and commercial returns are either $2.00 or $2.25, depending

upon usage.

82

82

BGE Gas Delivery Quarterly Profile

EBITDA excluding off-system sales and special itemsSee Appendix

Period CustomersEBITDA (millions)

Gains from Cost Sharing

(millions)2008

Q1 648,498 $77 $8

Q2 647,659 13 1

Q3 647,114 0 1

Q4 648,930 46 4

Total 2008 $136 $14

2009E 660,546 $133 $13

This slide details our gas delivery profile for 2008 broken down into

quarters and provides an estimate for full year 2009 gas delivery. In

2008, gas delivery contributed $136 million in EBITDA. For 2009,

estimated EBITDA from gas delivery is $133 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. 2008 experienced

unusually high gains in Off-System Sales due to warmer than normal

temperatures leading to more capacity available. 2008 Gains achieved

through the cost sharing programs were $14 million in 2008 and are

estimated to be $13 million in 2009.

83

83

2008 BGE Rate Base

($ in millions)

Electric Distribution

Gas Distribution

ElectricTransmission

Utility Plant $ 4,122 $ 1,357 $ 768

Additions to Rate Base 126 138 5

Deductions from Rate Base (2,084) (639) (340)

Total Rate Base $ 2,164 $ 856 $ 433

For 2008, our total average rate base was $2.2 billion from electric

distribution, $856 million from gas distribution, and $433 million related

to transmission, for a total of approximately $3.5 million. This represents

an increase of approximately 6% over 2007 average rate base.

Rate base represents shareholder investments in utility assets, upon

which BGE is authorized to earn a reasonable rate of return. Major

components include:

Utility Plant – gross utility plant and equipment

Additions to Rate Base – materials and supplies, gas storage,

generation regulatory asset and cash working capital

Deductions from Rate Base – accumulated depreciation, accumulated

deferred income taxes and net employee benefit plans

84

84

BGE ROE

(1) Excludes Special Item

Regulated & Book ROE

2006(1) 2007(1) 2008(1)

Regulated Electric Distribution 9.7% 7.1% 10.0%

Regulated Gas Distribution 8.7% 5.8% 7.7%

Blended Distribution 9.6% 6.7% 9.4%

Regulated Electric Transmission 10.7% 10.7% 14.3%

BGE Regulated ROE 10.0% 7.1% 10.0%

BGE Book ROE 9.7% 8.1% 9.4%

In 2008, BGE regulated ROE was 10% and GAAP ROE was 9.4%,

slightly higher than BGE’s ROE in 2007.

Regulated ROE does not include BGE Electric Standard Offer Service

return or gains from its Gas cost sharing program. For the three years

shown, these additional after-tax net income amounts were:

Electric SOS Gas Sharing

2006 $14.3M $6.0M

2007 $13.0M $6.8M

2008 $9.8M $8.4M

In 2008, both regulated and GAAP returns are adjusted to exclude the

effect of the $189 million March 2008 settlement agreement with the

State of Maryland and the Public Service Commission of Maryland.

85

85

Additional Modeling

• CEG Financial Results

• Credit Quality

• CEG Financial Outlook

• BGE

• Generation

– Plant Statistics p. 86

– Nuclear and Fossil Generation Statistics p. 87

– Generation Assets p. 88

– Fuel Mix p. 89

– Operational Performance p. 90

– Nuclear PPA Plants p. 91

• Customer Supply

• Global Commodities

86

86

Plant Statistics for 2008

Hillabee (gas fuel type) is under construction and will be online at the end of 2009 with an installed capacity of 740 MW

This slide does not reflect the impact of the Nuclear joint venture

Plant NamePrimary Fuel

Type Location

Installed Capacity

(MW)Percent Owned

Owned Capacity

(MW)

2008 Total

MWH's

NuclearCalvert Cliffs Nuclear Calvert Co., MD 1,735 100.0% 1,735 14.7Ginna Nuclear Ontario, NY 581 100.0% 581 4.7Nine Mile Point - 1 Nuclear Scriba, NY 620 100.0% 620 5.3Nine Mile Point - 2 Nuclear Scriba, NY 1,138 82.0% 933 7.4 Total Nuclear 4,074 3,869 32.2

Non-NuclearBrandon Shores Coal Anne Arundel Co., MD 1,286 100.0% 1,286 7.9C.P. Crane Coal/Oil Baltimore Co., MD 399 100.0% 399 1.7Conemaugh Coal Indiana Co., PA 1,711 10.6% 181 1.2Gould Street Gas Baltimore, MD 97 100.0% 97 0.0H. A. Wagner Coal/Oil/Gas Anne Arundel Co., MD 995 100.0% 995 2.1Handsome Lake Energy Gas Rockland Twp., PA 268 100.0% 268 0.0Keystone Coal Armstrong & Indiana Cos., PA 1,711 21.0% 359 3.0Notch Cliff Gas Baltimore Co., MD 120 100.0% 120 0.0Perryman Oil/Gas Harford Co., MD 355 100.0% 355 0.1Philadelphia Road Oil Baltimore Co., MD 64 100.0% 64 0.0Riverside Oil/Gas Baltimore Co., MD 228 100.0% 228 0.0Safe Harbor Hydro Safe Harbor, PA 417 66.7% 278 0.7Westport Gas Baltimore Co., MD 121 100.0% 121 0.0West Valley Gas Salt Lake City, UT 200 100.0% 200 0.3Grand Prairie Gas Alberta, Canada 85 100.0% 85 0.0

Subtotal Non-Nuclear 8,056 5,035 17.1

Qualifying FacilitiesACE Cogeneration Plant Coal Trona, CA 102 31.1% 32 0.3Chinese Station Biomass Jamestown, CA 20 45.0% 9 0.1Colver Power Project Waste Coal Colver Township, PA 104 25.0% 26 0.2Malacha Hydro Muck Valley, CA 32 50.0% 16 0.0Mammoth Lakes G-1 (50%) Geothermal Mammoth Lakes, CA 6 50.0% 3 0.1Mammoth Lakes G-2 (50%) Geothermal Mammoth Lakes, CA 13 50.0% 7 0.0Mammoth Lakes G-3 (50%) Geothermal Mammoth Lakes, CA 13 50.0% 7 0.0Panther Creek Waste Coal Nesquehoning, PA 80 50.0% 40 0.3Rio Bravo Fresno Biomass Fresno, CA 24 50.0% 12 0.1Rio Bravo Jasmin Coal Kern Co., CA 35 50.0% 18 0.1Rio Bravo Poso Coal Kern Co., CA 35 50.0% 18 0.1Rio Bravo Rocklin Biomass Placer Co., CA 24 50.0% 12 0.1SEGS IV (12.2%) Solar Kramer Junction, CA 33 12.2% 4 0.0SEGS V (4.2%) Solar Kramer Junction, CA 24 4.2% 1 0.0SEGS VI (8.8%) Solar Kramer Junction, CA 34 8.8% 3 0.0Sunnyside Cogeneration Waste Coal Sunnyside, UT 51 50.0% 26 0.2 Total Qualifying Facilities 630 232 1.6

Total Non-Nuclear 8,686 5,267 18.7

Total Generating Facilities 12,760 9,136 50.9

This chart shows a summary of our Generation plant statistics.

87

87

Nuclear and Fossil Generation Statistics2008 2009E 2010E 2011E 2012E

Nuclear

(MWh in thousands)

CCNPP1 7,159 7,555 6,980 7,636 6,472

CCNPP 2 7,514 6,958 7,457 6,866 7,488

NMP 1 5,346 4,918 5,334 4,989 5,363

NMP 2 7,413 7,977 7,271 7,993 7,927

Ginna 4,744 4,663 4,970 4,505 4,682

Total 32,176 32,071 32,012 31,989 31,932

Capacity Factor

CCNPP1 92.8 98.5 90.1 98.5 83.3

CCNPP 2 99.3 92.6 98.5 90.7 98.6

NMP 1 98.2 90.9 98.5 91.9 98.6

NMP 2 90.7 98.3 89.7 98.5 91.6

Ginna 93.7 92.3 98.5 89.3 92.5

Total 94.7 94.5 95.0 93.8 92.9

Uranium Hedge Percentage 100% 100% Not disclosed Not disclosed

Fossil

Fossil TWh (Excluding QFs) 17,105 17,646 19,397 19,656 19,744

PGD Reliability % (for coal fleet only) 86.1% 88.2% 90.6% 91.1% 91.0%

PGD Reliability % (for total fleet) 88.0% 89.8% 91.4% 91.9% 91.9%

Coal Hedge Percentage 100% 79% 9% 0%

Note: Data excludes impact of EDF JV

This chart shows generation statistics for our nuclear and fossil plants for 2008 – 2012E.

Also, it shows the hedge percentages for uranium and coal for 2009-2012.

From a production standpoint, Constellation Energy Nuclear Group (CENG) generated a

record 32 million megawatt-hours of electricity in 2008, the highest since the five reactors

became a fleet in 2005.

Three reactors had record generation in a refueling outage year and maintained a high

capacity factor: Calvert Cliffs Unit 1, had a 92.8 percent capacity factor; Ginna, 93.7 percent;

and Nine Mile Point Unit 2., a 90.7 capacity factor. Our two reactors that did not have

refueling outages in 2008 operated almost full time: Calvert Cliffs Unit 2 had a 99.3 percent

capacity factor, while Nine Mile Point 1 operated at 98.2 percent capacity.

On the reliability front, Nine Mile Point Unit 1 operated continuously for 519 days through

Oct. 23, and Calvert Cliffs Unit 2 has been operating non-stop for more than 660 days.

These accomplishments are tied to safe and thorough maintenance, including effective

refueling outages – work that we completed in record time. Calvert Cliffs was rated first in

the nation for refueling outages in 2008, with a 19.6-day outage. Among the 42 spring

refueling outages in 2008, Ginna was third with 20 days; and Nine Mile Point 2 was 11th,

with a 27-day outage.

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88

Generation Assets – 9,136 MW as of December 2008

Note: This slide does not reflect the impact of the Nuclear Joint Venture

This chart provides a view of our generation assets. As you can see, we maintain

assets primarily in the Mid-Atlantic region and California. This chart also shows you

the capacity of each asset and fuel type.

Assets are located in high value markets like PJM and New York.

Constellation Power Generation (CPG) took advantage of market and growth

opportunities by both adding megawatts and supporting construction of generation

facilities. Last year, CPG purchased the partially built Hillabee facility in Alabama

from Calpine and is continuing construction on that 774-megawatt natural gas

facility. In June, CPG purchased and began operating the West Valley peaking plant

near Salt Lake City. In December, we completed construction and began commercial

operation of the Grand Prairie peaker in Alberta, Canada. In addition, the scrubber

construction project at Brandon Shores, which will help us meet the Maryland’s

Healthy Air Act, is now more than 50 percent complete.

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89

CEG 2009ECoal 16.2 MMWh

Gas 0.9 MMWh

Nuclear 32.1 MMWh

Other 2.2 MMWh

Total 51.4 MMWh

Fuel Mix

CEG 2008

Coal 2,733 MW

Gas 965 MW

Nuclear 3,869 MW

Other 1,569 MW

Total 9,136 MW

CEG 2009ECoal 2,733 MW

Gas 1,705 MW

Nuclear 3,869 MW

Other 1,569 MW

Total 9,876 MW

CEG 2008Coal 16.4 MMWh

Gas 0.4 MMWh

Nuclear 32.2 MMWh

Other 1.9 MMWh

Total 50.9 MMWh

Coal, 32%

Gas, 2%Nuclear, 62%

Other, 4%

Coal, 30%

Gas, 11%Nuclear, 42%

Other, 17%

Coal, 28%

Gas, 17%Nuclear, 39%

Other, 16%

Coal, 32%

Gas, 1%Nuclear,

63%

Other, 4%

Owned Capacity

Generation

(1)

Note: This slide does not reflect the impact of the Nuclear Joint Venture

These charts show the capacity of our fleet by fuel type and generation by fuel type.

90

90

Operational Performance

(1) Delivered Generation Hours / Economic Generation Hours; excludes IPP’s

0

10

20

30

40

50

60

2003 2004 2005 2006 2007 2008 2009E

Nuclear Coal Oil and Gas Hydro and Renewables Other

TWh

Generation

75%

85%

95%

105%

2003

2004

2005

2006

2007

2008

2009

E

Reliability (1) (Fossil Plants)

75%

85%

95%

105%

2003

2004

2005

2006

2007

2008

2009

E

Capacity Factor (Nuclear Plants)

This slide does not reflect the impact of the Nuclear Joint Venture

• Total generation of 50.9M MWhrs in 2008 is projected to increase to 51.4M MWhrs in 2009. The increase is mainly due to the ramping up of West Valley and Grande Prairie.• Fossil reliability percentage has remained relatively constant since 2003. Reliability measures the actual delivered generation from our units over the desired generation reflected by a dispatch market signal.• Nuclear capacity factor of 94.7% in 2008 is projected to decrease to 94.5% in 2009, due mainly to higher projected outage days in 2009 (2008 was a record year for forced outage days).

91

91

Nuclear PPA Plants

Nine Mile Point Ginna

Unit Capacity (100%) Unit 1: 620 MWUnit 2: 1,138 MW

581 MW

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

100% Owned

Contract Terms

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

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. 90%.

TWh (100%) 14.4 4.7

Contracted Through: Unit 1: August 2009Unit 2: November 2011

June 2014

Other 105 MW uprate to be completed in 2012 83 MW uprate completed in 2006

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

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.

The RSA is modeled as a hedge by calculating the number of MWHRs we’d have to sell at

market price to fulfill the contract terms. This gives a ‘short’ power position, which when put

against our ‘long’ generation positions gives us a hedge ratio.

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 90% until the PPA ends in 2014.

92

92

Additional Modeling

• CEG Financial Results

• Credit Quality

• CEG Financial Outlook

• BGE

• Generation

• Customer Supply

– Customer Supply Overview p. 93

– Customer Supply Volumes p. 94

– Customer Supply Backlog p. 95

• Global Commodities

9393

93

Customer Supply Overview

Leading power and gas marketer in North America

Wholesale power marketer serving approximately 12,500 MW of peak load to utilities, co-ops, municipalities, and retail suppliers across North America

Leading retail electricity supplier providing energy products and services to over 15,000 customers and over 78 of the Fortune 100

Natural gas provider serving approximately 10,000 commercial, industrial, municipal, and local gas distribution and power facilities across North America

2009E Gross MarginRetail Power (44%)

Retail Gas (20%)

Wholesale Power (36%)

Both Retail Power and Retail Gas are expected to grow in 2009 as a

total percentage of the Customer Supply group as we move to optimize

margins and profitability.

94

94

Customer Supply Volumes

Power Gas

0

50

100

150

200

250

2004 2005 2006 2007 2008 2009E

TWh

Retail Power Wholesale Power

050

100150200250300350400450

2004 2005 2006 2007 2008 2009E

Bcf

As we focus on increasing margins and profitability in 2009, we are anticipating a contraction in the business and a reduction in market share

All three CSG business units are forecasting reduced volume growth in

2009 as compared to 2008 as we target higher margins to optimize

profitability and liquidity.

95

95

Customer Supply Backlog

0

100

200

300

400

500

600

2009E 2010E 2011E

Wholesale Power Retail Power Retail Gas

Gro

ss M

argi

n$

mill

ions

(1) Retail Gas backlog assumes (94% renewal rate)Note: Third quarter 2008 reported backlog for retail power included expected renewals

We have built backlog representing 79% of total Gross Margin we expect to realize in 2009

(1)

Taking a look at the Customer Supply Group backlog, we have built 2009 backlog through 2008 representing about 79% of the Gross Margin we expect to realize. In 2008, we increased our backlog for 2009 by $188 million for both Retail and Wholesale power. In 2009, we will continue to add to our total gross margin backlog, but expect to originate less volumes at higher unit margins. This reduction in volumes will result in reduced market share but will also help us to achieve higher levels of customer profitability.During the third quarter earnings call we had reported 2008 backlog for Retail Power inclusive of expected renewals. We have since discontinued this assumption given our anticipated reduction in volume.

96

96

Additional Modeling

• CEG Financial Results

• Credit Quality

• CEG Financial Outlook

• BGE

• Generation

• Customer Supply

• Global Commodities

– Divestiture Update p. 97

– Upstream Gas p. 98

– Shipping Assets p. 99

97

97

Pending Asset DivestituresInternational Coal & Freight Business• Signed a purchase and sale agreement to sell majority of business to a

subsidiary of Goldman Sachs (GS)• Expect to close in early Q2 2009

– Novation of certain key contracts to GS– Regulatory approvals needed are European Union Competition Committee, Korean

Competition Committee (received), FSA

Houston Downstream Gas Business• Signed a Purchase and Sale Agreement with Macquarie Cook Energy (MCE)• Have signed a Letter of Intent with MCE to have MCE provide wholesale

supply to support our retail gas business• Expect to close in Q2 2009

– Novation of key contracts– Regulatory approvals needed are Canadian Competition Commission and FERC

related

Based on today’s market prices estimated collateral returned to Constellation will be approximately $1 billion

98

98

Upstream Gas Assets

(1) Includes 28% ownership of Constellation Energy Partners (NYSE Arca: CEP), which is an oil and gas LLC (limited liability companyNote: Approximate value of CEG ownership in CEP $18 million assuming CEP unit price of $2.78 at 12/31/08

Black Warrior Basin CBM (AL)Cherokee Basin CBM (OK/KS) (3)Woodford shale (OK)Woodford shale (OK)Fayetteville shale (AR)North Louisiana CBM (LA)Ohio shaleHunton dewatering (OK)West Virginia CBMShallow GOM

Current Portfolio of Investments (1)

Constellation Energy Partners Unconventional Conventional

Estimated Net Proven Reserves

Average Net Daily

Production

CEG (excludes CEP ownership) as of 12/31/08

197 Bcfe 41.1 MMcfe

CEP (CEG % ownership)as of 9/30/08

63 Bcfe 13.6 MMcfe

Taking a closer look at our upstream gas assets, we are developing E&P projects in various locations with a majority of unconventional production, including coalbed methane, tight sands and shale. The CEP production and reserve estimates also shown on this page are representative of Constellation’s ownership interest in CEP.We have recently exited 4 assets for ~$60MM

99

99

Shipping Assets

We own a 50% interest in a shipping joint venture that owns and operates five freight ships for the delivery of coal and other dry bulk freight products.

• 4 Capesize ships with Dry Weight Capacity ranging from 149,507 MT to 173,149 MT

• 1 Panamax ship with Dry Weight Capacity of 69,235

•We own a 50% interest in a shipping joint venture that owns

and operates five freight ships for the delivery of coal and

other dry bulk freight products.

- 4 Capesize ships with Dry Weight Capacity ranging

from 149,507 MT to 173,149 MT

- 1 Panamax ship with Dry Weight Capacity of 69,235

100

Non-GAAP Appendix

101

101

Summary of Non-GAAP Measures

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

Adjusted EPS Reported GAAP EPSYTD 2008 Actual 21, 33 102 - 105YTD 2007 Actual 21 102 - 105Q108 Actual 21 102 - 105Q208 Actual 21 102 - 105Q308 Actual 21 102 - 105Q408 Actual 21 102 - 105EPS Guidance 41 102

Merchant Gross Margin 51, 52, 53, 54, 71 Income from Operations / Net Income 110 - 113Merchant Projected Gross Margin 71, 73 110 - 113

BGE Gross Margin 49, 50, 70, 80 Income from Operations / Net Income 106 - 109BGE EBIT 81, 82 106BGE Projected Gross Margin and Below Gross Margin 70, 80 106 - 109

Debt to Total Capital 56 Debt Divided by Total Capitalization 114

Funds From Operations 56 Operating, Investing and Financing Cash Flow 115

102

102

Adjusted EPS 2008, 2007 and Quarterly – Consolidated

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

RECONCILIATION:CEG Consolidated 2007 2008

($ per share) Total Q1 08 Q2 08 Q3 08 Q4 08 Total

ACTUAL RESULTS:

Reported GAAP EPS 4.50$ 0.81$ 0.95$ (1.27)$ (7.75)$ (7.34)$

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

4.51 0.81 0.95 (1.27) (7.75) (7.34)

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

Synthetic fuel facility results (0.02) 0.01 0.01 - - 0.02

Non-qualifying hedges 0.01 (0.19) (0.19) 0.07 (0.07) (0.39)

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

Impairment - Upstream - - - (0.49) (0.65) (1.14)

Impairment - Nufcor equity securities - - - - (0.04) (0.04)

Merger related transaction costs - - - (0.21) (6.43) (6.72)

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

Maryland Settlement - BGE Credit - - (0.70) - (0.01) (0.71)

Effective Tax Rate Impact - BGE Credit - 0.04 0.01 0.01 0.03 0.09

Class action lawsuit settlement - - - (0.05) - (0.05)

NDTF impairment - - - (0.09) (0.33) (0.42)

CAIR SO2/NOX impairment - - - (0.13) 0.04 (0.09)

Goodwill impairment - - - (0.94) (0.01) (0.96)

CEP impairment - - - (0.19) (0.24) (0.43)

Total Special Items and Non-qualifying Hedges (0.09) (0.14) (0.87) (2.03) (7.78) (10.91)

Adjusted EPS 4.60$ 0.95$ 1.82$ 0.76$ 0.03$ 3.57$ NON-GAAP MEASURE

EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact of

special items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

NOTEThe sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and the effects of dilution shares.

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

103

103

Adjusted EPS 2008, 2007 and Quarterly – Merchant

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

RECONCILIATION:Merchant 2007 2008

($ per share) Total Q1 08 Q2 08 Q3 08 Q4 08 Total

ACTUAL RESULTS:

Reported GAAP EPS 3.72$ 0.40$ 1.56$ (1.38)$ (8.06)$ (7.58)$

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

3.73 0.40 1.56 (1.38) (8.06) (7.58)

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

Synthetic fuel facility results (0.02) 0.01 0.01 - - 0.02

Non-qualifying hedges 0.01 (0.19) (0.19) 0.07 (0.07) (0.39)

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

Impairment - Upstream - - - (0.49) (0.65) (1.14)

Impairment - Nufcor equity securities - - - - (0.04) (0.04)

Merger related transaction costs - - - (0.14) (6.49) (6.72)

Workforce reduction costs (0.01) - - (0.01) (0.05) (0.05)

Class action lawsuit settlement - - - (0.05) - (0.05)

NDTF one-month lag adjustment - - - (0.09) (0.33) (0.42)

CAIR SO2/NOX impairment - - - (0.13) 0.04 (0.09)

Goodwill impairment - - - (0.94) (0.01) (0.96)

CEP impairment - - - (0.19) (0.24) (0.43)

Maryland Corporate Tax Rate change 0.05 - - - - -

Total Special Items and Non-qualifying Hedges (0.04) (0.18) (0.18) (1.97) (7.84) (10.27)

Adjusted EPS 3.77$ 0.58$ 1.74$ 0.59$ (0.22)$ 2.69$ NON-GAAP MEASURE

EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact of

special items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

NOTEThe sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and the effects of dilution shares.

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

104

104

Adjusted EPS 2008, 2007, Quarterly – BGE

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

RECONCILIATION:BGE 2007 2008

($ per share) Total Q1 08 Q2 08 Q3 08 Q4 08 Total

ACTUAL RESULTS:

Reported GAAP EPS 0.69$ 0.41$ (0.60)$ 0.11$ 0.29$ 0.21$

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

0.69 0.41 (0.60) 0.11 0.29 0.21

Special Items:

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

Effective Tax Rate Impact - BGE Credit - 0.04 0.01 0.01 0.03 0.09

Maryland Settlement credit - BGE - - (0.70) - (0.01) (0.71)

Merger related transaction costs - - - (0.06) 0.06 -

Workforce reduction costs - - - - (0.02) (0.02)

Total Special Items (0.05) 0.04 (0.69) (0.05) 0.06 (0.64)

Adjusted EPS 0.74$ 0.37$ 0.09$ 0.16$ 0.23$ 0.85$ NON-GAAP MEASURE

EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact of

special items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

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

105

105

Adjusted EPS 2008, 2007 and Quarterly – ONR

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

RECONCILIATION:Other Nonregulated 2007 2008

($ per share) Total Q1 08 Q2 08 Q3 08 Q4 08 Total

ACTUAL RESULTS:

Reported GAAP EPS 0.09$ -$ (0.01)$ -$ 0.02$ 0.03$

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

0.09 - (0.01) - 0.02 0.03

Special Items:

Workforce reduction costs - - - (0.01) - -

Total Special Items - - - (0.01) - -

Adjusted EPS 0.09$ -$ (0.01)$ 0.01$ 0.02$ 0.03$ NON-GAAP MEASURE

EARNINGS GUIDANCE Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact of

special items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

NOTEThe sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and the effects of dilution shares.

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

106

106

2008 BGE Gross Margin, Below Gross Margin and EBIT

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy and to highlightthe primary driver of earnings at our Regulated Utility. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period. GAAP to NONGAAP Walk2008 Notes: a b

BGE Gross Margin Categories Electric Gas BGE GAAPMaryland Settlement

Credit

Maryland Settlement Credit -

Effective Tax

Other Adjustments Below GM

Other Notes

Non-GAAP

Electric 800$ 800$ 189$ 989$ Gas 330 330 330 Total Regulated 800$ 330$ 1,130$ 189$ -$ 1,318$

Operating & Maintenance (380) (157) (537) (3) (540)$ Workforce Reduction Costs (5) (1) (6) 6 e - Depreciation & Amortization (184) (44) (228) (228) BTaxes Other than Income Taxes (139) (36) (175) 176 d - Income from Operations 92 92 184 550 Other Revenue and Expense 28 1 29 (195) d, c (166) EBIT N/A N/A N/A 385 AFixed Charges (113) (27) (140) 19 c (121) Income Before Income Taxes 7 66 73 264 Income Tax expense 4 (26) (22) (59) (16) (2) e (98) Income from Continuing Operations 11 40 51 166 Preference Stock Dividends (10) (3) (13) (13) Net Income 1$ 37$ 38$ 127$ (16)$ 4$ 153$

EBITDA

a Adjustment to remove the Maryland Settlement Credit charge and related income and other tax effects that management views as a special item. EBIT 385 Ab Adjustment to remove the effective tax rate adjustment related to the Maryland Settlement Credit charge that management views as a special item. D & A 228 Bc Adjustment to move Interest Income recorded in Other Income to Fixed Charges (to show a fixed charge amount net of interest income). EBITDA 613 d Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. e Adjustment to remove workforce reduction costs that management views as a special item. Electric 477

Gas 136 BGE 613

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.

Adjustments in Arriving at Non-GAAP

($ million)

107

107

2007 BGE Gross Margin and Below Gross Margin

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

GAAP to NONGAAP Walk2007

BGE Gross Margin Categories Electric Gas BGE GAAP

Other Adjustments Below GM

Other Notes

Non-GAAP

Electric 955$ 955$ 955$ Gas 323 323 323 Total Regulated 955$ 323$ 1,278$ -$ 1,278$

Operating & Maintenance (376) (158) (534) (5) a (539)$ Depreciation & Amortization (188) (47) (234) (234) Taxes Other than Income Taxes (140) (36) (176) 176 b - Income from Operations 251 83 334 505 Other Revenue and Expense 24 2 27 (195) a, b, c (169) EBIT N/A N/A N/A 337 Fixed Charges (98) (28) (125) 24 c (101) Income Before Income Taxes 178 57 235 236 Income Tax expense (70) (25) (95) 8 d (88) Income from Continuing Operations 108 32 140 148 Preference Stock Dividends (10) (3) (13) (13) Net Income 98$ 29$ 126$ 8$ 135$

a Adjustment to move Other Income / Exp to O&M from Other Revenue and Expense.b Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. c Adjustment to move Interest Income recorded in Other Income to Fixed Charges (to show a fixed charge amount net of interest income).d Adjustment to remove the Maryland Corporate Tax Rate expenses ($8M) that management views as a special item.

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.

108

108

Q408 BGE Gross Margin and Below Gross Margin

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

GAAP to NONGAAP WalkQ4 2008 Notes: a b

BGE Gross Margin Categories Electric Gas BGE GAAPMaryland

Settlement Credit

Maryland Settlement Credit -

Effective Tax

Other Adjustments Below GM

Other Notes

Non-GAAP

Electric 235$ 236$ 236$ Gas 95 95 95 Total Regulated 235$ 95$ 331$ -$ -$ 330$

Operating & Maintenance (89) (39) (128) (128)$ Merger & Strategic Alternative 8 3 11 (11) c - Workforce Reduction Costs (4) (2) (6) 6 e - Depreciation & Amortization (46) (11) (57) (57) Taxes Other than Income Taxes (35) (9) (44) 44 f - Income from Operations 69 37 106 100 Other Revenue and Expense 6 - 6 (48) d, f (41) EBIT N/A N/A N/A 103 Fixed Charges (30) (7) (37) 4 d (33) Income Before Income Taxes 45 30 75 70 Income Tax expense (2) (17) (19) 1 (5) (2) e (25) Income from Continuing Operations 43 13 56 45 Preference Stock Dividends (3) - (3) (3) Net Income 40$ 13$ 53$ 1$ (5)$ (7)$ 42$

a Adjustment to remove the Maryland Settlement Credit charge that management views as a special item.b Adjustment to remove the effective tax rate adjustment related to the Maryland Settlement Credit charge that management views as a special item.c Adjustment to remove merger & strategic alternative costs that management views as a special item.d Adjustment to move Interest Income recorded in Other Income to Fixed Charges (to show a fixed charge amount net of interest income).e Adjustment to remove workforce reduction costs that management views as a special item.f Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense.

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.

Adjustments in Arriving at Non-GAAP

($ million)

109

109

Q407 BGE Gross Margin and Below Gross Margin

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

GAAP to NONGAAP WalkQ4 2007

BGE Gross Margin Categories Electric Gas BGE GAAP

Other Adjustments Below GM

Other Notes

Non-GAAP

Electric 235$ 236$ 236$ Gas 92 92 92 Total Regulated 235$ 92$ 327$ -$ 327$

Operating & Maintenance (101) (43) (144) (2) a (146)$ Depreciation & Amortization (47) (11) (58) (58) Taxes Other than Income Taxes (34) (9) (43) 43 b - Income from Operations 53 29 82 123 Other Revenue and Expense 7 1 8 (48) a, b, c (41) EBIT N/A N/A N/A 82 Fixed Charges (28) (7) (35) 7 c (28) Income Before Income Taxes 32 23 55 54 Income Tax expense (17) (12) (29) 8 d (20) Income from Continuing Operations 15 11 26 34 Preference Stock Dividends (3) - (3) (3) Net Income 12$ 11$ 23$ 8$ 31$

a Adjustment to move Other Income / Exp to O&M from Other Revenue and Expense.b Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. c Adjustment to move Interest Income recorded in Other Income to Fixed Charges (to show a fixed charge amount net of interest income).d Adjustment to remove the Maryland Corporate Tax Rate expenses that management views as a special item.

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.

($ million)

110

110

2008 Merchant Gross Margin and Below Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Generation, Customer Supply, and Global Commodities). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

GAAP to NONGAAP Walk2008 Notes: a b c d e f g h i

Merchant Gross Margin Categories GAAPNonqualifying

Hedges

Certain Operating Expenses

Gross Receipts Tax / Aggregator

Fees Fly AshDecommissioning

Revenue CAIR

Upstream - Cash Flow

Hedge Reclass

Sale of Upstream

Gas Properties Synfuels

Other Adjustments Below GM

Other Notes

Non-GAAP

Generation 1,956$ (34)$ 26$ (19)$ (4)$ 1,924$ Customer Supply 765 (77) 688 Global Commodities 260 115 25 (4) 24 (1) 418 **Total 2,981$ 115$ (34)$ (77)$ 26$ (19)$ 25$ (4)$ 24$ (5)$ -$ 3,030$

Operating & Maintenance (1,730)$ 34 37 (26) (1,685)$ Impairment Losses on Long Lived Assets & Other Costs (742) 742 k - Workforce Reduction Costs (15) 15 l - Merger and Other Strategic Alternative Costs (1,204) 1,204 m - Depreciation & Amortization (287) 2 (285) Asset Retirement Obligation (68) (68) Taxes Other than Income Taxes (124) 40 84 j - Income from Operations (1,190) 992 Gain on Sales of Upstream Gas Assets 25 (25) - Other Revenue and Expense (101) 19 2 (1) 53 j, n, o (27) EBIT N/A 965 Fixed Charges (191) 5 12 n (174) Income Before Income Taxes (1,457) 790 Income Tax expense 100 (45) (9) 2 (1) (5) (350) k, l, o (308) Income from Continuing Operations (1,357) 482 Income from discontinued operations - - Net Income (1,357)$ 70$ -$ -$ -$ (0)$ 15$ (2)$ -$ (4)$ 1,760$ 482$

a Adjustment to remove economic, nonqualifying hedges of gas transport and storage contracts.b Adjustment to reclassify operating expenses to Non-GAAP gross margin.c Adjustment to reclass gross receipts tax and aggregator fees from operating expenses to Non-GAAP gross margin.d Adjustment to reclass fly ash expenses to Non-GAAP operating and maintenance expense.e Adjustment to remove decommissioning revenues from non-GAAP gross margin measure and include in Other Income. The offsetting decommissioning expense was recorded in accretion of asset retirement obligations.f Adjustment to remove Special Item and related tax benefit, which relates to the write-down of our SO2 and NOx emission allowance inventory to reflect market prices at December 31, 2008.g Adjustment to remove Special Item and related tax benefit, which relates to the reclassification of cash-flow hedges (from the impaired Upstream Gas properties) with a pre-tax net gain deferred in Accumulated other Comprehensive Loss into Revenues. h Adjustment to reclassify gain on sale of Upstream Gas properties to Non-GAAP gross margini Adjustment to remove Synfuel earningsj. Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. k Adjustment to remove Special Items (Impairment losses on long lived assets and fly ash class action settlement) and related tax benefit ($270 million), which are not included in determining Merchant Below Gross Marginl Adjustment to remove Special Items (workforce reduction) and related tax benefit ($6 million), which are not included in determining Merchant Below Gross Marginm Adjustment to remove Special Items (merger and strategic alternative costs), which are not included in determining Merchant Below Gross Marginn Adjustment to move Interest Income recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).o Adjustment to remove Nuclear Decommission Trust Fund Losses (Special Items of $153 million) and related tax benefit ($77 million), which are not included in determining Merchant Below Gross Margin

** Excludes $141 million of operating expenses, depreciation, depletion and amortization, and interest expense associated with our Upstream Gas properties and $(1) million of other gross 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.

Adjustments in Arriving at Non-GAAP

($ million)

111

111

2007 Merchant Gross Margin and Below Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Generation, Customer Supply, and Global Commodities). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

GAAP to NONGAAP Walk2007 Notes: a b c d e f g h

Merchant Gross Margin Categories GAAPNonqualifying

Hedges

Certain Operating Expenses

Gross Receipts Tax /

Aggregator Fees Fly Ash

DecommissioningRevenue

Gain on Sale of CEP

Units Synfuels

Impairment &

Workforce Reduction

Other Adjustments Below GM

Other Notes Non-GAAP

Generation 1,700$ (41)$ 12$ (18)$ 26$ 1,679$ Customer Supply 889 (15) (74) 801 Global Commodities 654 12 63 27 756 **Total 3,243$ (3)$ (41)$ (74)$ 12$ (18)$ 63$ 53 -$ 3,236$

Operating & Maintenance (1,792)$ 41 35 (12) 15 (1,713)$ Impairment Losses on Long Lived Assets & Other Costs (20) 20 - Workforce Reduction Costs (2) 2 - Merger and Other Strategic Alternative Costs - - Depreciation & Amortization (270) 20 (250) Asset Retirement Obligation (68) (68) Taxes Other than Income Taxes (110) 39 (1) 72 j - Income from Operations 980 1,205 Gain on sale of equity of CEP 63 (63) - Other Revenue and Expense 55 18 (0) (97) j, k (24) EBIT N/A 1,181 Fixed Charges (87) 9 18 k (60) Income Before Income Taxes 1,012 1,121 Income Tax expense (333) 1 (91) (9) - j, l (433) Income from Continuing Operations 679 687 Income from discontinued operations (1) 1 i - Net Income 678$ (2)$ -$ -$ -$ -$ -$ 4 13 (6)$ 687$

a Adjustment to remove economic, nonqualifying hedges of gas transport and storage contracts.b Adjustment to reclassify operating expenses to Non-GAAP gross margin.c Adjustment to reclass gross receipts tax and aggregator fees from operating expenses to Non-GAAP gross margin.d Adjustment to reclass fly ash expenses to Non-GAAP operating and maintenance expense.e Adjustment to remove 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.f Adjustment to move gain on sale of stock by CEP to gross margin to reflect management's view of this activity as part of operations.g Adjustment to remove Synfuel Earnings.h Adjustment to remove Special Items and related tax benefit which are not included in determining Merchant Below Gross Margin.i Discontinued operations is considered a special item by management.j Adjustment to reflect management's view of these items as Other Income / Expense. k Adjustment to move Interest Income recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).l Adjustment to remove Maryland Tax Rate change special item

** Excludes $115 million of operating expenses, depreciation, depletion and amortization, and interest expense associated with our Upstream Gas properties and $(1) million of other gross 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.

Adjustments in Arriving at Non-GAAP

($ million)

112

112

Q408 Merchant Gross Margin and Below Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Generation, Customer Supply, and Global Commodities). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

GAAP to NONGAAP WalkQ4 2008 Notes: a b c d e f g

Merchant Gross Margin Categories GAAPNonqualifying

Hedges

Certain Operating Expenses

Gross Receipts

Tax / Aggregator

Fees Fly AshDecommissioning

Revenue CAIR

Sale of Upstream

Gas Properties

Other Adjustments Below GM

Other Notes

Non-GAAP

Generation 455$ (8)$ 4$ (4)$ 447$ Customer Supply 229 (20) 209 Global Commodities (52) 21 (12) (66) (109) Total 632$ 21$ (8)$ (20)$ 4$ (4)$ (12)$ (66)$ -$ 548$

Operating & Maintenance (432)$ 8 10 (4) (419)$ Impairment Losses on Long Lived Assets & Other Cos (265) 265 k - Workforce Reduction Costs (13) 13 l - Merger and Other Strategic Alternative Costs (1,177) 1,177 m - Depreciation & Amortization (79) (79) Asset Retirement Obligation (18) (18) Taxes Other than Income Taxes (30) 10 20 h - Income from Operations (1,382) 32 Gain on Sales of Upstream Gas Assets (66) 66 - Other Revenue and Expense (105) 4 99 h, j, i (2) EBIT N/A 30 Fixed Charges (81) 3 j (78) Income Before Income Taxes (1,634) (48) Income Tax expense 170 (8) 5 (160) k, l, i 7 Income from Continuing Operations (1,464) (41) Income from discontinued operations - - Net Income (1,464)$ 13$ -$ -$ -$ 0$ (7)$ -$ 1,417$ (41)$

a Adjustment to remove economic, nonqualifying hedges of gas transport and storage contracts.b Adjustment to reclassify operating expenses to Non-GAAP gross margin.c Adjustment to reclass gross receipts tax and aggregator fees from operating expenses to Non-GAAP gross margin.d Adjustment to reclass fly ash expenses to Non-GAAP operating and maintenance expense.e Adjustment to remove decommissioning revenues from non-GAAP gross margin measure and include in Other Income. The offsetting decommissioning expense was recorded in accretion of asset retirement obligationf Adjustment to remove Special Item and related tax benefit, which relates to the write-down of our SO2 and NOx emission allowance inventory to reflect market prices at December 31, 2008.g Adjustment to reclassify gain on sale of Upstream Gas properties to Non-GAAP gross marginh Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. i Adjustment to remove Nuclear Decommissioning Trust Fund Losses (Special Items of $122 million) and related tax benefit ($61 million), which are not included in determining Merchant Below Gross Marginj Adjustment to move Interest Income recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).k Adjustment to remove Special Items (Impairment losses on long lived assets and fly ash class action settlement) and related tax benefit ($95 million), which are not included in determining Merchant Below Gross Margl Adjustment to remove Special Items (workforce reduction) and related tax benefit ($5 million), which are not included in determining Merchant Below Gross Marginm Adjustment to remove Special Items (merger and strategic alternative costs), which are not included in determining Merchant Below Gross 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.

Adjustments in Arriving at Non-GAAP

($ million)

113

113

Q407 Merchant Gross Margin and Below Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Generation, Customer Supply, and Global Commodities). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

GAAP to NONGAAP WalkQ4 2007 Notes: a b c d e f g

Merchant Gross Margin Categories GAAPNonqualifying

Hedges

Certain Operating Expenses

Gross Receipts

Tax / Aggregator

Fees Fly AshDecommissioning

Revenue CEP Gain Synfuels

Other Adjustments Below GM

Other Notes

Non-GAAP

Generation 372$ (10)$ 4$ (4)$ 6$ 368$ Customer Supply 337 (20) 317 Global Commodities 228 (13) 13 4 231 Total 937$ (13)$ (10)$ (20)$ 4$ (4)$ 13$ 10$ -$ 917$

Operating & Maintenance (454)$ 10 10 (4) 3 (434)$ Impairment Losses on Long Lived Assets & Othe - - Workforce Reduction Costs - - Merger and Other Strategic Alternative Costs - - Depreciation & Amortization (72) 3 (70) Asset Retirement Obligation (16) (16) Taxes Other than Income Taxes (25) 25 h - Income from Operations 370 397 Gain on CEP IPO 12 (12) - Other Revenue and Expense 20 8 4 (2) (31) h, i (1) EBIT N/A 396 Fixed Charges (25) 2 6 i (17) Income Before Income Taxes 377 379 Income Tax expense (147) 4 (3) (146) Income from Continuing Operations 230 233 Income from discontinued operations - - Net Income 230$ (9)$ -$ (2)$ -$ -$ 13$ 13$ (12)$ 233$

a Adjustment to remove economic, nonqualifying hedges of gas transport and storage contracts.b Adjustment to reclassify operating expenses to Non-GAAP gross margin.c Adjustment to reclass gross receipts tax and aggregator fees from operating expenses to Non-GAAP gross margin.d Adjustment to reclass fly ash expenses to Non-GAAP operating and maintenance expense.e Adjustment to remove decommissioning revenues from non-GAAP gross margin measure and included in Other Income. The offsetting decommissioning expense was recorded in accretion of asset retirement obligationsf Adjustment to reclassify gain on sale of CEP to Non-GAAP gross marging Adjustment to remove Synfuel Earnings.h Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. i Adjustment to move Interest Income recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).

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.

Adjustments in Arriving at Non-GAAP

($ million)

114

114

Debt to Total Capital Debt to Total Capital is a non-GAAP presentation of total capitalization that excludes unamortized discounts and premiums from debt, and includes minority interests in equity. In addition, we reflect a 50 percent equity credit for our trust preferred securities, 60-year hybrid debt, and EDF preferred stock classified as debt for accounting purposes, similar to the evaluation performed by major credit rating agencies. Management believes this non-GAAP measure provides 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 facilitates comparability between periods.

RECONCILIATION:

GAAP Balances

Total long-term debt (excl. TOPrS, gross of current portion) 7,474.4$ 7,474.4$ 4,788.2$ 4,788.2$

Fair value decrease (increase) in fixed to floating rate swap included in long-term debt (55.9) (11.8)

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 50% Equity credit to trust preferred securities (125.0) - (125.0) 50% Equity credit for 60-year hybrid debt securities (225.0)

50 % EDF Preferred Stock classified as LTD for accounting purposes (500.0)

MEHC Debt - Restricted Cash (1,000.0) Short-term borrowings 855.7 855.7 14.0 14.0 Unamortized discount and premium (41.9) (4.8) - Total Debt 8,545.9 6,681.9 5,055.1 4,923.1

BGE Preference Stock Not Subject To Mandatory Redemption 190.0 190.0 190.0 190.0 Minority Interests 20.1 - 19.2 Common shareholders' equity 3,523.7 3,181.4 5,340.2 5,340.2 Subtotal 3,713.7 3,391.5 5,530.2 5,549.4 50% Equity credit to trust preferred securities 125.0 - 125.0 50% Equity credit for 60-year hybrid debt securities 225.0 EDF Preferred Stock 500.0 Total Equity 3,713.7 4,241.5 5,530.2 5,674.4

Total Capitalization 12,259.6$ 10,923.4$ 10,585.3$ 10,597.5$

Non-GAAP Balances

December 31, 2008

Non-GAAP Balances

December 31, 2007

GAAP Balances

115

115

FFO – 2008, 2007

The non-GAAP financial measure of Funds from Operations (FFO) is a non-GAAP measure that approximates recurring cash flows from operations exclusive of all non-cash items and working capital. We utilize this non-GAAP measure as it is helpful in understanding our recurring operating cash performance as earnings generally includes large non-cash items.

RECONCILIATION: December 31, 2008 December 31, 2007

Net cash provided by operating activities (GAAP Measure) (1,274) 928

ADD: Changes in working capital (excluding derivative assets and liabilities) and other 922 247

ADD: Cash portion if merger cancellation costs (special item) 662 -

ADD: BGE Settlement (special item) 189 -

ADD: OLA Depreciation (S&P calculated) 256 314

SUBTRACT: Interest on Imputed Debt (S&P analysis) (112) (49)

SUBTRACT: Current Taxes on Special Items (6) -

SUBTRACT: Capitalized interest (excluding BGE borrowed funds AFC) (46) (17)

SUBTRACT: Repayment of securitized debt (59) -

Funds from operations (FFO - NONGAAP Measure) 532 1,423

116

Constellation Energy2009 Analyst Presentation

February 18, 2009