constellation energy Q4 2005 Earnings Presentation

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Constellation Energy2006 Analyst Presentation

January 31, 2006

Kevin Hadlock:

Good morning everyone. I am Kevin Hadlock, Director of Investor Relations for Constellation Energy. Welcome to our fourth quarter and full-year 2005 earnings call. I’m glad that so many of you could join us today.

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

Before we begin the presentation, let me remind you that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties.

For a complete discussion of these risks, we encourage you to read our documents on file with the SEC.

Our presentation today is being webcast, and the slides are available on our website, which you can access at constellation.com under Investor Relations.

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Use of Non-GAAP Financial MeasuresIt is important to recognize that in certain instances in this presentation we have adjusted our actual financial results, prepared in accordance with generally accepted accounting principles (GAAP), for special items (which we define as items that are not related to our ongoing, underlying business or which distort comparability of results) and certain economic, non-qualifying hedges. We also provide earnings guidance in terms of adjusted earnings, which excludes special items and certain economic, non-qualifying hedges. We believe that the resulting pro-forma, non-GAAP information provides a picture of our results that is comparable among periods since it excludes the impact of items such as workforce reduction costs, which may recur occasionally, but tend to be irregular as to timing, thereby distorting comparisons to prior periods. However, investors should note that non-GAAP measures involve judgments by management and in particular, judgments as to what is or is not classified as a special item or an economic, non-qualifying hedge to be excluded from adjusted earnings. We note that such information is not in accordance with GAAP and should not be viewed as an alternative to GAAP information. A reconciliation of pro-forma information to GAAP information is included either on the slide where the information appears or on one of the slides in the Non-GAAP Measures section provided at the end of the presentation. Please see the Summary of Non-GAAP Measures included in the Appendix to find the appropriate GAAP reconciliation and its related slide(s). These slides are only intended to be reviewed in conjunction with the oral presentation to which they relate.

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

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

Moving to slide 4…

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Non-Solicitation This communication is not a solicitation of a proxy from any security holder of FPL Group or Constellation Energy. Constellation Energy intends to file with the Securities and Exchange Commission a registration statement that will include a joint proxy statement/prospectus of Constellation Energy and FPL Group and other relevant documents to be mailed to security holders in connection with the proposed transaction. WE URGE INVESTORS TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT FPL GROUP, CONSTELLATION ENERGY, AND THE PROPOSED TRANSACTION. A definitive proxy statement will be sent to security holders of FPL Group and Constellation Energy seeking approval of the proposed transaction. Investors and security holders will be able to obtain these materials (when they are available) and other documents filed with the SEC free of charge at the SEC’s website, www.sec.gov. In addition, a copy of the joint proxy statement/prospectus (when it becomes available) may be obtained free of charge from Constellation Energy, Shareholder Services, 750 E. Pratt Street, Baltimore, MD 21202, or from FPL Group, Shareholder Services, P.O. Box 14000, 700 Universe Blvd., Juno Beach, Florida 33408-0420.

This communication shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.

FPL Group, Constellation Energy, and their respective directors and executive officers of FPL Group and Constellation Energy and other persons may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding FPL Group’s directors and executive officers is available in its proxy statement filed with the SEC by FPL Group on April 5, 2005, and information regarding Constellation Energy’s directors and executive officers is available in its proxy statement filed with the SEC by Constellation Energy on April 13, 2005. Information regarding J. Brian Ferguson, a director of FPL Group elected since the date of the filing of the 2005 definitive proxy statement, can be found in FPL Group’s filing on Form 10-Q dated August 4, 2005. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available.

This communication is not a solicitation of a proxy from any security holder of Constellation Energy. Constellation Energy intends to file a registration statement with the Securities and Exchange Commission that will include a joint proxy statement and prospectus and other relevant documents to be mailed to security holders in connection with the proposed merger of Constellation Energy and FPL Group.

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

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Agenda

9:15 – 9:45

9:10 – 9:15

8:40 – 9:10

8:35 – 8:40

8:15 – 8:35

8:00 – 8:15

Time

Mayo ShattuckComments on Merger

SpeakerTopic

Follin SmithFinancial Review

AllQuestions & Answers

Tom BradyNewEnergy

Felix DawsonCommodities Group

Mayo ShattuckOverview

Good morning, everyone. Thank you for joining us on the call. As you all know, our practice over the past four years has been to meet with you in New York City to review prior year results and to present our business plan. Given the merger, we decided to have an extended phone call. The approach today is fairly consistent with the presentation we have made historically. Importantly, the substance of the outlook you will hear is entirely consistent with what we have told you before.

Here is our agenda for this morning. First, we will address our standalone, pre-merger business plan. I’ll start with an overview.

After that, Felix Dawson, President and co-CEO of our Commodities Group will discuss wholesale competitive supply operations. Tom Brooks, Chairman of our Commodities Group, and George Persky, the other President and co-CEO of the Commodities Group, are also here with us this morning.

Next, Tom Brady, who heads Corporate Strategy and our retail businesses, will discuss NewEnergy.

Then, Follin Smith, our CFO and Chief Administrative Office will cover our financials. In the interest of time, Follin’s presentation will provide some highlights of the Generation and BGE outlook as well. Mike Wallace and Ken Defontes are here to take questions.

Lastly, I will share a few thoughts on Constellation Energy’s pending merger with FPL Group and then we will take your questions.

Turning to slide 6…

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2005 Earnings

-0.14Non-Qualifying Hedges

See Appendix

$3.35 - $3.602005 Earnings Guidance

16.0%$0.50$3.12$3.62Adjusted EPS

-0.01Special Items

$3.12$ 3.47Reported EPS

%$20042005

Change($ per share)

16% EPS growth in 2005

For 2005, Constellation earned a record $3.62 per share, excluding special items and certain economic, non-qualifying hedges. This represents growth of 16% over 2004’s adjusted earnings of $3.12 per share, above the top end of our guidance range of $3.60 per share. Exceeding the guidance range is even more impressive given the loss of earnings contribution from Oleander and Panama, which were sold in 2005. At the beginning of the year, we described our forecasted EPS of $3.60 as representing an 11% growth rate. As GAAP required restatement of both 2004 and 2005 results to exclude 12¢of earnings from Oleander and Panama, the year-over-year increase is actually 16% - a great year. Additionally, we have met or exceeded our earnings guidance for 17 consecutive quarters—a significant accomplishment that is indicative of our commitment to deliver what we promise.


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Consistent Earnings Growth

$2.46

$2.82

$3.12

$3.62

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

2002 2003 2004 2005

Adjusted Earnings Per Share

14% Annual Growth

[1] Adjusted for the effect of special items and certain economic, non-qualifying hedgesSee Appendix

[1]

As we enter the next phase of our growth and evolution, it is extremely gratifying to reflect on what our employees have achieved during the past four years. This team has created a leading competitive position that combines our superior risk management skills and intimate knowledge of physical energy logistics with an intense focus on meeting our customer’s needs. As a result, we are now in a position, through our proposed merger with FPL Group, to become an end-game player in a consolidating industry.

In terms of our financial performance, we have achieved superior results leading to significantly enhanced shareholder value. Our adjusted earnings per share have grown nearly 50% since 2002, or 14% per year on average.


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(50%)

(25%)

0%

25%

50%

75%

100%

125%

150%

175%

10/3

1/01

12/3

1/01

2/28

/02

4/30

/02

6/30

/02

8/31

/02

10/3

1/02

12/3

1/02

2/28

/03

4/30

/03

6/30

/03

8/31

/03

10/3

1/03

12/3

1/03

2/29

/04

4/30

/04

6/30

/04

8/31

/04

10/3

1/04

12/3

1/04

2/28

/05

4/30

/05

6/30

/05

8/31

/05

10/3

1/05

12/3

1/05

Total Return for Shareholders

Delivered total shareholder return of nearly 29% per annum since 10/31/2001

CEG 159%

S&P 500 21%

S&P Elec 39%

Stock Price ChangeTotal Return Including Dividends

CEG 193%

S&P Electric 68%

S&P 500 22%

Our success in growing the business has translated into significant value for our shareholders. Since the team came together in November 2001,Constellation Energy shares have appreciated 159%. When considering the dividends that we have paid, this amounts to an average total return of nearly 29% per annum. We have significantly outperformed our peers in the S&P 500 Electric Utility Index and the broader markets, as the market recognizes the strength of our business model. We are well-positioned to continue that trend.We understand that dividends are also important to our shareholder base, and have maintained our commitment to grow dividends approximately in line with our earnings growth. Yesterday, we announced that the Board approved an increase in the annual dividend of 13%, or 17¢, from $1.34 to $1.51 per share. We have also indicated that as part of the proposed merger with FPL, we would increase our dividend to match FPL’s upon closing. Including yesterday’s dividend increase and based on FPL’s current dividend, Constellation shareholders will receive an estimated increase of 53% in their dividend payment. In total, this will be a 114% increase in the span of 4 years.Moving to slide 9…

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Creating an End-Game Player

• Participation along full value chain

• Strong customer-facing businesses

• Balanced footprint

• Best-in-industry risk management capabilities

• Strong balance sheet

• Disciplined investment approach

• Efficiency and cost focus

Focus on creating an end-game player in consolidating industry

Several years ago, we committed to competitive markets in the belief that they would continue to grow and become a greater part of the demand landscape. We were determined to be a player in that market, and the model we employed to get there is essentially a simple one: Build and leverage scale in our core businesses and markets and drive down costs to bolster our competitive position. We continually looked one step ahead to the next growth market in ways that logically extended our current competencies. Our model has created continual opportunities for future success.

To drive Constellation’s position as an end-game player in a consolidating industry, we want to expand our participation along the full value chain in a balanced way, diversifying our exposure to any given region or regulatory framework. We believe the ideal platform for our strong commercial front-end includes the support of balanced deregulated generation in each region and a strong balance sheet. To ensure that we are efficiently using investor capital, we have committed to grow the platform with a disciplined investment approach. If we do not find opportunities to redeploy capital in projects that provide sufficient risk-adjusted returns, we will return it to shareholders. Finally, while we enjoy a strong leadership position, we must continue to focus on driving greater efficiency and lower cost in our generation fleet, headquarters and throughout our competitive platform.

We have come a long way to achieving the criteria that we see as necessary to be a long-term leader in this market. I’d like to spend a few minutes this morning reviewing what we have accomplished toward these goals, as well as where we go from here.


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Participating Along Full Value Chain

• Baltimore Gas and Electric – Transportation and distribution utility for 1.2 million electricity customers and 620,000

gas customers in Central Maryland

• Constellation Generation– Owns 11,856 Megawatts of primarily base load coal and nuclear generation capacity

• Constellation Commodities Group– Wholesale competitive supply business acting as an intermediary between producers and

consumers of electricity, coal and natural gas– Manages the sale of our fleet’s output and the fleet’s fuel inputs

• Constellation NewEnergy– Nation’s largest supplier of electricity to commercial and industrial customers

In recognition of the fact that we may have some people on the line that may be new to Constellation and unfamiliar with our story, let me take a minute to walk you through our growth and changes of the past few years. Through a series of strategic moves, Constellation has evolved into the leading competitive supplier. Today, Constellation Energy meaningfully operates in all parts of the energy value chain, while maintaining our strong roots by running a traditional regulated utility, BGE, which delivers stable earnings and cash flow.

The Merchant segment captures our competitive businesses—Generation, Commodities Group and NewEnergy.

Constellation Generation owns about 12,000 megawatts of primarily base load coal and nuclear generation capacity

Constellation Commodities Group runs a thriving wholesale competitive supply business acting as an intermediary between producers and consumers of electricity, coal and natural gas. The Commodities Group also manages the sale of our fleet output and the fleet’s hedgable fuel inputs. Finally, NewEnergy, which we acquired in 2002, is the nation’s largest supplier of electricity to commercial and industrial customers, including 70 of the FORTUNE 100. It is penetrating deregulated markets to grow its retail competitive supply franchise in both gas and electricity and improve its strong market position.

Constellation’s combination of businesses span the energy value chain providing a stable foundation on which to build for the future.


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0

3,000

6,000

9,000

12,000

15,000

18,000

2003 2004 2005

Peak

MW

s

Strong Customer-Facing Businesses

3%2,00059,100Other

22,300

2,400

10,100

7,800

Wholesale Load

(Peak MWs)

130,200

18,800

33,500

18,600

Target Market Size (Peak MWs)

17%Total

13%ERCOT

30%PJM

40%NEPOOL

Target Market Share

Wholesale Competitive Supply NewEnergy

Focus on satisfying customer needs

NewEnergy

Reliant

TXU

Great PlainsSUEZ

Direct (US Only)

Source: KEMA August 2005

[1] Source: Platts Megawatt Daily 1/9/2006. 2005 volumes through 9/30/05[2] Source: Platts Gas Daily 12/12/05. 2005 volumes through 9/30/05

#17#7Rank

5.1

#1

364.7

2005

2.2Gas (Bcf / day) [2]

#1Rank

458.8Power (MWhs) [1]

2004FERC Reported Volume

Deregulation created an entire class of customer needs, and Constellation Energy is on the forefront of creating products and services that meet these needs. We have created an unmatched competitive position by combining our superior risk management skills and intimate knowledge of physical energy logistics with an intense focus on customer needs. We have every reason to be confident about our growth prospects for the future.

On the left side of the chart, you can see that we have become the #1 player in electricity markets from #13 four years ago, and the #7 gas marketer from #17 in 2004. In wholesale power load serving, we have an estimated market share of 40% in NEPOOL and 30% in PJM. Overall, our share of our target market is 17%.

In NewEnergy, we continue to significantly outpace the competition and have 15,500 peak megawatts under contract. We are pleased with the performance of this business and continue to see great opportunities for growth.


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Balanced Footprint

8007,2004,8002,400ERCOT

4,6466,7004,7002,000Other Areas

11,85637,80015,50022,300Total

-9,8002,0007,800NEPOOL

6,41014,1004,000 10,100PJM

Generation (MWs)

Total (Peak MWs)

Retail (Peak MWs)

Wholesale (Peak MWs)

Constellation is geographically diversified, and the merger with FPL will provide greater balance between load and generation

We are not only big in deregulated markets, but we are also balanced across regions. This chart shows our peak load versus owned generation capacity. In PJM, we have just over 6,400 MWs of generation and 14,100 megawatts of peak load with a 55% load factor. This is a very balanced position. However, in the other major deregulated regions of NEPOOL and ERCOT, we have built a substantial customer-facing business without the support of significant generating capability.

Through the merger with FPL, we will become more balanced between generation and load served, which will allow us to build a “virtual utility” and to create a powerful competitive position from which to grow over the long term. Adding FPL’s generating assets to Constellation’s load serving business in NEPOOL and ERCOT creates that powerful long-term competitor in the deregulated regions and, in the near-term, will drive some real benefits like maximizing the value of renewable energy credits, ancillaries and capacity products and avoiding hedging costs of crossing the bid-offer spread.


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Leading Risk Management Capabilities

• In customer-facing businesses, risk management means dissecting and quantifying risks with precision and intentionally eliminating unwanted risk

• In trading, risk management means taking calculated exposures that have more upside than downside and result in high returns on capital at risk (VaR)

• Key underpinnings to good risk management

– Founded on Goldman Sachs systems

– Strong control environment and culture

– Focus on physical markets

– Intensive credit exposure management

CEG has an unparalleled track record of avoiding surprises through strong risk management

We are very proud of our risk management capabilities and have an unparalleled track record of avoiding surprises through strong risk management. In our customer-facing businesses, strong risk management means that we obsessively dissect and quantify risks with precision. We price all risk components in our products and manage our portfolio to minimize unacceptable risks. We constantly assess our performance with hindsight to ensure that our risk analyses were good, and we refine them as we move through time.

In trading, we have achieved strong results while only placing moderate amounts of capital at risk. By taking trading positions in physical markets where our competitive skills and deep knowledge of market information gives us an advantage, we have consistently had high returns on capital at risk.


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Productivity Gains

80

60

40

90

$0

$50

$100

$150

$200

2005 2006 2007

Projected Actual

• Exceeded on 2005 productivity commitment– Permanent reduction in cost base – Incremental gross margin from fleet– Headquarters efficiencies

We began the year with a pre-tax productivity target of $80 million. We had a phenomenal year and exceeded our 2005 plan by $10 million to recognize total 2005 productivity of $90 million. Our generation fleet drove the vast majority of these gains with $41 million in gross margin improvements and cost cutting associated with nuclear outages. Another $30 million was additional generation savings due to a strong fleet management approach that resulted in reduced labor and materials expense. Constellation Energy headquarters also realized significant savings primarily in the areas of reduced SOX cost and lower spending on IT projects.

For 2006, we plan to deliver an incremental $40 million in productivity gains by leveraging our fleet management approach and further reducing outage days.

We remain firmly committed to delivering a permanently lower cost-per-unit structure, which enhances our ability to compete and results in an annuity for our shareholders in the competitive environment.


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Balance Sheet Improvement

54.6%52.9%

49.9%

46.5%

42.8% 41.6%

30.0%

40.0%

50.0%

60.0%

2001 2002 2003 2004 2005 2006E

Net Debt to Total Capital

See Appendix

While growing the business is critical to our success, we would not be able to take advantage of the market opportunities without a solid balance sheet. Constellation has been able to grow the business rapidly and improve our balance sheet at the same time. We continue to improve the strength of the balance sheet and expect to be at 41.6% net debt to capital by the end of 2006. Follin will talk about this more in the Financials.


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Maryland Regulatory Environment• End of rate freeze for BGE residential customers

– Residential rates have been frozen since 1999 despite rapidly rising fuel costs

– Staff recommended a deferral approach to phase in the impact of higher power prices for electric customers

Amount of deferral capped at about $280 million before taxesDeferral period of 8 months beginning July 2006Recovery period of 15 months beginning March 2007Customer participation voluntary on an “opt-in” basis

– Expect any deferral of revenue will be fully recovered from customers in future months

• Proposed Maryland emissions rules– Maryland legislative and regulatory proposals to control NOx, SOx and

mercury emissions– Regional or national approach is more appropriate, given more than 70% of

Maryland air quality problems originate from out-of-state sources– Capital spending budget reflects expected outcome

Let me spend a moment to discuss the current Maryland regulatory environment. As we have been discussing with you for a number of years, price freeze service for BGE residential customers ends in June of this year. As a result of higher energy prices, residential customers will see higher power prices beginning July 1. Because the percentage increase is expected to be large coming off six years of frozen prices at a level 6.5% below 1993 rates, the PSC opened a case to consider a “more measured transition to market-based prices.” The Staff recommended a deferral approach, which caps the deferral amount at about $280 million and phases in the impact of the higher prices over an 8-month period, followed by a 15-month recovery period. The proposal specifies certainty of cost recovery through the creation of a regulatory asset. The staff has recommended that participation in the deferral plan should be voluntary on an “opt-in” basis. We are confident that any ultimate deferral of revenue will be fully recovered in future months.

Maryland is also looking at environmental regulatory and legislative proposals for local requirements on power plant emissions that might go beyond what is mandated by the federal rules issued in March 2005. These proposals will be debated in the General Assembly between now and mid-April. Our capital budget reflects our expectation for additional controls that will be required to meet new Maryland clean air implementation plans. These added costs would begin in 2007, and will include added O&M expenditure for using existing equipment on a year-round basis.


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Long-Term Earnings Outlook

Guidance of $3.65 - $3.95 per share for 2006Confirm 2007 guidance of $4.75 - $5.00 per share

2008 EPS growth of approximately 10%-15% over 2007

$2.46$2.82

$3.12

$3.62$3.65 - $3.95

$4.75 - $5.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

2002 2003 2004 2005 2006E 2007E 2008E

Adjusted Earnings Per Share[1] Adjusted for the effect of special items and certain economic, non-qualifying hedges; Estimates assume midpoint of the range

See Appendix

[1]

Our outlook for 2006 is for earnings per share of $3.65 to $3.95. We continue to believe 2007 will be $4.75-$5.00 per share as a standalone company. Rising commodity prices, a more highly hedged fleet, a growing backlog of wholesale transactions and actual productivity gains make us even more comfortable with this assessment than we were when we first provided this guidance last January.

We have increased our outlook for 2008 as a standalone company for growth of 10%-15% over 2007, again reflecting a fleet more highly hedged at higher prices coupled with modest expectations for our fundamental growth drivers.

When you consider the merger with FPL, our shareholders will not only continue to see the benefits derived from our standalone plan but will also have more diverse sources of growth and a stronger balance sheet from which to grow. I will speak a bit more on the merger in my concluding remarks at the end of the presentation.

At this point, I will turn the presentation over to Felix to talk about the Commodities Group…

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Constellation Energy Commodities Group

Felix Dawson

Thanks, Mayo. Good morning everyone.

In the next 20 minutes, I will give the outlook for Constellation Commodities Group, our wholesale sales and risk management arm. Turning to our agenda on page 19 …

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19

Agenda

• Business Overview

• Business Area Outlook:

– Power

– Natural Gas

– Coal

– Portfolio Management & Trading

• Summary of 2006 Gross Margin Outlook

I’ll begin by providing a brief overview of our business model, focusing on how we consistently apply this model across each of our four business lines. As I think you’ll agree, the Constellation Commodities Group that we discuss today has expanded significantly over the past year into the broader business we set out to become. We’ve grown, we’ve diversified, and we’ve proven once again that our unsurpassed portfolio management and trading capabilities allow us to navigate even the most highly volatile commodity markets, such as those we’ve witnessed this year. Gulf hurricanes, above average summer temperatures, and non-static regulatory environments have made the competitive energy marketplace a challenging and exciting place. We’ve once again proven that the Commodities Group is up to this challenge, as our 2005 results and our 2006 gross margin outlook demonstrate.

Turning to page 20,

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2005: Consistent Growth Across Commodities

Retained leading position in power while doubling volumes in gas and coal

COALPOWER GAS

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

% of FERC Reported Volumes* Natural Gas Reported Volumes (Bcf/day)** Coal Deliveries (MM tons)***

***Exclusive of agency volumes

2.6%4.7%

5.9%7.5% 8.0%

0%

2%

4%

6%

8%

10%

2001 2002 2003 2004 2005

0.02.2

5.1

0

1

2

3

4

5

6

7

2003 2004 3Q05

5.6 5.6

12.6

0

2

4

6

8

10

12

14

2003 2004 2005

**Source: Platt’s Gas Daily*Source: Platt’s Megawatt Daily; 2005 results are 3Q YTD

2005 was another outstanding year for the Commodities group, as each of our customer-focused business lines performed well. We retained our number one position in the power markets, substantially increased our delivered volumes in gas, and delivered over 12 million tons of coal to customers in the U.S., Europe, and the Far East, as well as to our own fleet. While we continue to focus on margins, not volumes, we believe they are indicative of levels of commercial growth.

Our results from the year confirm the strength of these businesses.

Turning to page 21 …

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2005: Continued Gross Margin Growth

Generated $378M of new business and created $415 million of future gross margin, 80% of which will be realized within four years

VALUE CREATIONGROSS MARGIN [1]

44% CAGR

$598M

[1] Gross margin excludes non-qualifying hedges and synfuel, includes upstream gas contribution margin

$65$186 $221

$139 $158

$186

$201

$378

$-

$100

$200

$300

$400

$500

$600

2001 2002 2003 2004 2005

Realization of Backlog Current Gross Margin

158 186 201

37887171 197

415

$-

$200

$400

$600

$800

2002 2003 2004 2005

Current Gross Margin Future Gross Margin

See Appendix

Combined, Commodities created $378 million of new business recognized as current year gross margin, or CGM. Coupled with the realization of previous years’ backlog, Commodities earned $598M in gross margin in 2005. Looking back to 2001, when we embarked on our current course of success, we’ve achieved a compound annual growth rate of 44%.

Also notable is the backlog of future earnings we’ve created across each of our business lines. Future gross margin, or FGM, which represents new business originated in 2005 that will be realized in future years, was $415 million, more than double the amount from 2004. Importantly, 80% of this will be realized over the next four years and will provide meaningfully to our 2006 gross margin target. Total Value creation, which includes the CGM and FGM originated in 2005, was $793 million, up $395 million from the prior year.

Turning to page 22, let’s review the business model that has been central to our accomplishments.

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A Simple Business Model … Diversified

• Our simple business model is consistently applied across all three commodities: We provide physical products to upstream and downstream customers, and we rely on effective, conservative portfolio management

• We’ve built a truly diversified platform across three commodities –power, natural gas and coal

• Three tenets ground our wholesale model: Customer Business Drives Growth: We grow the business by serving a balanced mix of upstream and downstream customers in power, natural gas and coal marketsFleet Risk Management and Optimization: Our wholesale platform manages risk in and adds value to CEG’s physical assetsCapability & Scale: Our Portfolio Management & Trading capability and our scale have enabled us to deploy risk capital at attractive returns and manage customers’ exposure to price and volume variability at healthy margins

Our diversified platform reduces risk and enhances growth opportunities

Last year during our meeting, we spoke to you about the simple business model we employ. We provide physical energy products to upstream and downstream customers, earning margins by effectively managing our portfolio of owned and contractual assets. We also mentioned our plans to extend our model into new business areas – upstream and downstream natural gas and coal.

Today, we’re happy to be speaking with you about the success of these efforts. The developing businesses we described a year ago have now become core elements of Commodities’ strategy and are substantial contributors to both current and future gross margin. The roll-out of these businesses was accomplished faster than we had planned and each business is exceeding our initial expectations.

Commodities now offers a truly diversified platform marked by consistent application of the business model that brought us so much success in the power markets. We continue to focus on physical, customer-oriented products; we manage the risk and optimize the value of CEG’s owned assets; and we use our portfolio management and trading capabilities to both manage risk and deploy risk capital to generate attractive returns.

We believe that our coal and gas businesses reduce the relative exposure of our overall performance to a single business. And looking forward, we’re now able to explore investment opportunities across each of the lines of business, ensuring our capital is directed toward the opportunities, markets, and customer segments that will provide the greatest returns for our investors.


23

23

Producers Consumers

Natural Gas

Power

Portfolio Management

& Trading

Coal

• Merchant Generators

•Small to medium-sized North American producers

•Global producers trying to accomplish long term sales to power generators

•Distribution Utilities

•Various types of market area consumers

•Power generators in the US, Europe and Far East who can receive seaborne coal

A Truly Diversified Customer Platform

This is how we see Constellation Commodities Group today. Threecommodity business lines, each customer-focused, and all supported by our portfolio management and trading capabilities. In power we serve the needs of merchant generators and distribution utilities through our load serving business, mid-marketing sales efforts, and with other structured products. In natural gas, we serve customers across the value chain, beginning upstream with small-to-medium sized producers, across the transportation and storage network, and ending with various types of market area customers, including local distribution companies, and gas-fired power generators. In our international coal business, we’re employing the same customer-focus to link global producers seeking long-term sales to power generators in the US, Europe and Far East who can receive seaborne coal.

Finally, central to all of this is a Portfolio Management & Trading platform that comprises the core of the Commodities Group’s competitive advantage. We’ve spent years building the team, valuation tools, and infrastructure that comprise our PM&T operations, and we believe they are unsurpassed in the industry.

Turning to page 24, let me walk you through each area …

24

24

• In the fall 2005 auctions we were awarded approximately 33% of load volumes auctioned in theNortheast and Mid-Atlantic

• In 2006 we expect peak load of approximately 22,000 – 23,000 MW (market share between 16 - 17%) while maintaining attractive margins

East Target Market: 70,600 MW

Central Target Market: 44,300 MW

West Target Market: 19,500 MW

Modeling Assumptions 2005 2006ETarget Market (MW) 130,000 134,400Peak Load Served (MW) 24,000 22,000 - 23,000Load Factors 45 - 55% 45 - 55%Market Share 18% 16 - 17%Contracted Margin Range ($ per Mwh) $2 - $4 $2 - $4

Power: Full Requirements Market

West (TX, WSCC, Can)

0

1,000

2,000

3,000

05 Peak 06 Outlook

Peak

MW

s

East (NE, NY, SE)

0

2,000

4,000

6,000

8,000

10,000

05 Peak 06 Outlook

Peak

MW

s

Central (PJM, Midwest)

11,000

12,000

13,000

14,000

15,000

16,000

05 Peak 06 Outlook

Peak

MW

s

Starting with our Power business, comprised of two parts: Full Requirements Power and Mid-Market & Structured Products.

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

We expect margins for Full Requirements new business contracted in 2006 to remain at $2 to $4/MWh and are forecasting peak megawatts served to be about the same as 2005. In the fall of 2005, in the key Northeast and Mid-Atlantic markets, we won about a third of the total load awarded by utilities which is consistent with past results, so we believe our outlook is reasonable. As you know, last week Maryland held auctions for price freeze service, and while we are not able to discuss the outcome of the auction at this time, results were in line with our business plan.

Given these considerations, we expect 2006 current-year gross margin to be in-line with prior year’s, and for this business to continue to contribute meaningfully to our backlog.

Turning to page 25

25

25

Mid-Market Sales

$34 mm

Structured Products$70 mm

2005 New Business$104MM

Mid-market SalesIncreased internal focus on existing and new CCG markets

Generator ProductsHigh prices and volatility facilitating aggressive hedgingOpportunities to provide private equity investors, bank-owned assets, and development projects cash flow certainty

Restructurings/DivestituresSignificant opportunities continue to surface as companies unwind portions of their power business and/or specific risk positions

Mid-market SalesExecution oriented sales,

typically small volumes with low risk

Generator ProductsUnit contingent purchases of bulk energy from wholesale

generators

Restructurings/DivestituresAcquisitions of contractual asset

portfoliosRestructurings of load or supply

contracts for risk/return benefit

Power: Mid-Market & Structured Products

Mid-Market Sales

$32mm

Structured Products$91mm

2006E New Business$123MM

Continues to perform well; Forecasting 18% growth

Growth Drivers

Mid-Market & Structured Products includes two groups of activities:

First, mid-market sales includes short-dated, liquid hedges for producers and consumers of power. In 2005, we generated $34 million in gross margin. We expect similar performance from this business in 2006 generating about $32 million.

Second, Structured Products includes the more complex, structured hedge products we provide to customers. In contrast to mid-marketing, these are non-standard products that often provide more tailored and long-dated risk management solutions. Within this area, we continue to see opportunities to provide unit contingent products to generators and to participate in restructurings and divestitures, as customers look to exit positions in the power business and as we identify opportunities in our own portfolio to remove long-dated risks for attractive returns.

Our market leading position in power enables us to provide a level of responsiveness in structure and competitiveness of price that makes Constellation the preferred provider in many areas. We expect these businesses combined to generate $123M in 2006 current year gross margin.

Turning to Page 26

26

26

Power: 2006 Gross Margin Outlook

56% of power gross margin target of $355M is in the backlog

8%$330 $355 Gross Margin

24%$162 $201

104 123 Current Year Origination

$58 $77 Backlog Realization

Mid-Market and Structured Products

-8%$168 $155



Full Requirements Power

Change20052006E($ in millions)

Summarizing the gross margin outlook for our power business, we expect 2006 total gross margin to be $355 million, slightly above 2005 which was a particularly strong year for this business line. We based our new business targets on reasonable assumptions given past performance and an assessment of the opportunities we see for 2006, and we are forecasting 20% growth year-on-year. Our forecasted realization of backlog is down slightly year-on-year, primarily driven by the shape of margin realization on load contracts entered into in ’04 and ’05.

While our full-requirements power business continues to thrive and produce meaningful earnings, we expect it to produce proportionately less of the overall gross margin as other businesses grow.

Turning to the next page

27

27

Natural Gas: Integrated Gas Business Overview

Over the past two years, Commodities has built an integrated merchant natural gas business that is in its nature, market presence and profitability a suitable complement to our market-leading power business

Power End-Users

End-Users

Portfolio Mgmt &

Trading

Transmission

Midstream/Interstates

Generation

ProductionGas

Physical orientation with contractual assets along the value chainCustomer-centric model, leveraging knowledge of the physical systemStrategy to build to similar scale as Commodities Power business

Our integrated natural gas platform is now in place. In a little more than a year, we’ve built a business that has the people, the capabilities, and the scale to support our position as a key player in the North American natural gas market.

Our objective was to build a business that in its basic construction, in the scope of its market presence, and in its profitability would be a suitable complement to our market-leading power business, and we think we’ve met that objective.

We see tremendous opportunity to grow this business in the coming years, and as is the case across each of our business lines, we will measure success substantially by our ability to generate attractive, risk-adjusted returns on the capital we deploy.

Turning to page 28, let’s take a closer look at our upstream gas business ….

28

28

Natural Gas: Upstream

• We’ve created an upstream gas business fully consistent with our existing business model and integrated into an already proven risk management approach

• A focused strategy: targeted small, independent E&P companies previously served by exiting merchants and too small for money-center banks

• Healthy market appetite for our bundled offering of risk management services and capital in the form of debt, mezzanine or equity

2005 Accomplishments• Opportunities greatly exceeded

expectations– Acquired properties in TX,

AL– Current proved reserves of

219 Bcf; current daily production over 21 Mcf/day

• Expanded our partnering activities and customer base

We’ve discussed before the strategy that we employed when building our load-serving business in power. When numerous companies were tempering theirparticipation in the load business, we saw opportunity, and within several years, we were the leading wholesale supplier of power in the US and earning healthy margins. We saw a similar opportunity in an underserved segment of the upstream gas business. The Commodities Group provides risk management services to small, independent upstream companies with physical and operational expertise. To meet the needs of these customers, our price and volume risk management services often come bundled with capital.

The past year’s accomplishments in the upstream gas business exceeded our expectations. The upstream portfolio is generating strong returns and is a key contributor to current and future period earnings. We now have 219 Bcf of proved reserves in our portfolio based on independent third party estimates, with current production over 21 million cubic feet/day.

We believe 2006 is going to be another strong year for our upstream gas business. With the portfolio scale and market presence we’ve built in 2005, we now have a strong pipeline of opportunities to add to our existing customer business. And as in Power, as our upstream activity grows, we will look to rebalance our portfolio through new deals, restructurings, and divestitures.

Our successes on the upstream side were mirrored by our downstream business. Turning now to slide 29 …

29

29

Natural Gas: Downstream

• Our downstream gas business leverages Constellation’s customer-focused risk management capabilities across a wide range of services– End-user natural gas

marketing– Acquisition and management

of strategic transportation and storage capacity

• Exodus of key players from the downstream sector while commodity prices and structural changes have increased the need for our services

2005 Accomplishments• Competitive scale and market

presence achieved well-ahead of expectations

• Successful expansion of Houston office: 80 employees

• Physical throughput of 5-6Bcf/day:– Storage (annual): 6 Bcf– Transportation: 1-2 Bcf/day– Other marketing: 3-4 Bcf/day

• #7 in reported volumes in Q3[1]

[1] Source: Platt’s Gas Daily; 3Q05 North American Gas Marketer Rankings; 12/12/05

In our downstream gas business, we’ve applied Commodities’ core risk management capabilities and customer focus to provide a variety of services across the midstream and downstream value chain. Our customers include wholesale natural gas buyers such as utilities, large industrials, power generators, & retail aggregators. In addition to serving these customers, we invest in strategic transportation and storage capacity to support multi-region marketing and trading activity.

We’ve benefited from investing in a solid business opportunity that others have left. Only two of the top 10 gas marketers from 2001 are still in the business, and it’s not due to lack of demand from the downstream sector. Industry trends such as skyrocketing gas prices and the potential globalization of the gas market by LNG have greatly increased the need for the services and skills that our downstream gas business provides, and we are seeing increased value from our more significant base of customers.

These factors have led to strong results from our downstream business. We achieved competitive scale and market presence well-ahead of expectations. We’ve built out our Houston office, which now has over 80 employees. And with physical throughput of over 5 Bcf/day, we became the seventh largest marketer of natural gas in the third quarter.

Turning to page 30,

30

30

Natural Gas: 2006 Contribution Margin Outlook

28% of Natural Gas gross margin target of $159M is in the backlog

[1] Upstream Gas contribution margin[2] Favorable (F) designates year-on-year change of over 100%

F$40 $159 Gross Margin

F$19 $64


($1)$17 Backlog Realization

Downstream Gas

F [2]$21 $95



Upstream Gas [1]


We expect our combined natural gas businesses to generate $159 million in 2006 gross margin.

Of that amount, $95 million will come from upstream activity and $64 million will come from our downstream business. On the upstream side, we expect to create $67 million in 2006 gross margin from current year origination, while the remaining $27 million will come from backlog realization. Downstream, we project $47 million of new business to complement $17 million of margin already in the backlog. Our downstream new business target is consistent with our second-half 2005 run-rate.

Of the total gross margin target for our natural gas business, 28% is in the backlog.

Turning to our coal business on page 31 …

31

31

Coal: Overview

• 2005 saw the creation of a successful international coal business with better than expected results

• A producer and consumer customer business built around a large-scale global portfolio of coal, freight and terminal contracts

• In addition to substantial margin generation, the coal platform gives Commodities the option to pursue opportunistic expansion into other commodities in the UK

2005 Accomplishments• 12.6mm tons of coal delivered • Built significant backlog of

business for 2006 and beyond– 20.6mm tons in backlog

• Covered set up and operating costs in first full year

• Contractually enabled with over 25 customers with 15 more near completion

• Completed transactions in 17 countries

Our coal business is a producer and consumer customer business built around a large-scale global portfolio of coal, freight, and terminal logistics. We use our logistics and risk management expertise to optimize margins arising from structural differences in coal prices around the world. And by working with coal users to increase their coal flexibility, we’re able to provide the most cost-effective coal supply that meets their requirements.

As we exceeded the modest growth expectations we set for this business in 2005, we are forecasting continued progress this year as this business gathers momentum.

2005 was marked by several key accomplishments

•Our coal group delivered 12.6 million tons of coal to international and domestic third party customers and to our own fleet

•We’ve currently arranged for future delivery of 20 million tons to third parties, giving us a significant backlog of business for 2006 and beyond

•Our international coal business was active in 17 countries. We’re contractually enabled with over 25 customers globally and have 15 others nearing completion, giving us one of the most robust lists of customers in the industry

The coal business has substantially increased our market presence in Europe and will allow us to opportunistically pursue growth initiatives in the power and gas markets abroad should attractive opportunities arise.


32

32

Coal: 2006 Gross Margin Outlook

90% of coal gross margin target of $66M is in the backlog

F$24 $66 Gross Margin




The gross margin outlook for our coal services business is supported by the strong backlog we created in 2005 and our current pipeline of customer business.

Our $66 million gross margin target for the coal business includes $59 million already under contract and an additional $7 million to come from current year origination.

Turning to our Portfolio Management & Trading business on page 33

33

33

In both Portfolio Management and Trading we take a return oriented approach to managing risk, seeking attractive returns for the risk assumed

Portfolio Management & Trading: Overview• Risk management is at the core of our Commodities Group’s business

– Portfolio Management manages risks related to our portfolio of physical and contractual assets and accepts and manages risk associated with new customer business along the various physical commodity chains in which we operate

Generation assets and entitlementsFull requirements powerCoal supplyGas transportation/storage/production

– Trading deploys risk capital in traded regional commodity markets where we have customers and have an edge

Provides market intelligence and execution services to Portfolio Management as well

• We are well positioned to increase returns through PM&T as we continue to focus risk capital and risk management activities where we have a competitive advantage driven by:– Capabilities (people, infrastructure and risk management culture)– Intelligence (physical logistics, markets and products)– Scale

We’ve built an impressive track record of managing the risks in our portfolio while effectively deploying risk capital to earn substantial financial returns.

Our portfolio management group is responsible for the near-term value in our aggregate portfolio of physical and contractual assets. They seek to earn additional returns above and beyond the value of the portfolio at the start of the year. Additionally, they assume and manage the risks associated with new customer business.

Our closely related trading business deploys risk capital in actively traded regional energy commodities where we have customer business and an edge in our physical knowledge. Trading also supports Commodities’ three customer businesses by providing market intelligence and execution services.

Our competitive advantage in PM&T begins with the capabilities provided by our people, infrastructure, and risk management culture. We have taken the risk management and risk-taking infrastructure from our power business and have enhanced it over the past four years to provide a scalable, multi-commodity platform. And the people in PM&T are some of the best and most-experienced in the business. We take these unique capabilities and apply them to markets where we have informational advantages based on our in-depth knowledge of physical logistics, and we continually look to capitalize on opportunities that arise as the result of the scale and scope of our portfolio.

While there are some differences in the types of risks inherent in portfolio management versus trading, we manage them as a combined business, seeking attractive overall returns on risk capital.

34

Slide 34 shows three broad metrics we use to assess our PM&T operations: mark-to-market value at risk, hedge percentages, and gross margin. We closely monitor our mark-to-market value at risk. Increased levels of VaR in the 3rd and 4th

quarters are attributable to increased volatility in the marketplace and the extension of our trading capability into the expanding areas of our business. Average VaR for the year was $4.7 million with Q4 averaging $8 million. We continue to manage a well-hedged power portfolio, with over 95% of our power and fuel hedged for 2006. As we have done in the past, as we see opportunities to increase our hedge percentages in 2007 and beyond, we will do so. In 2005, we delivered a strong performance in PM&T, earning $204 million of gross margin, up $111 million over 2004. The increase was driven by our ability to earn returns on risk capital in PM&T as gains on trading positions more than offset higher than expected costs associated with serving fixed price load. As we discussed on the third quarter earnings call, we did experience higher costs to serve load in the face of a confluence of extreme temperatures and high commodity prices and volatility due to the active Gulf hurricane season. However, the trading portfolio was positioned to benefit throughout the year from some of the same commodity market dislocations which caused the increase in costs to serve load. The increase in trading performance and activity reflects our continued focus on expanding our deployment of risk capital leveraging our knowledge of physical power, gas and coal markets. With a disciplined approach to deployment of risk capital and managing portfolio risks, we expect $173 million from PM&T in 2006, a slight decrease from 2005 as we are not anticipating market conditions and associated opportunities to repeat themselves in 2006, but do expect to benefit from the increased scale and scope of the overall portfolio due to the continued growth of our power, gas, and coal business. Turning to page 35…

34

-

3.0

6.0

9.0

12.0

15.0

2004 1Q05 2Q05 3Q05 4Q05

VaR

(in

mill

ions

)

Portfolio Management & Trading : 2006 Gross Margin Outlook

2005 market environment presented many opportunities to enhance returns by deploying prudent amounts of risk capital

-15%$204 $173 Gross Margin


Percent Hedged @ 12/30/05 2006 2007 2008Power 95% 82% 79%Fuel 99% 82% 61%

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

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

2005 Average VaR: $4.7 million

35

35

Key growth drivers: • Backlog increase year-on-year accounts for 52% of the $154 million growth target• New business growth from Power and the first full year of Gas operations

Summary: 2006 Gross Margin Outlook

26%$598 $752 Total-15%$204 $173 Total Portfolio Management & Trading

204 173 Current Year Origination$0 $0 Backlog Realization

Portfolio Management & TradingF$24 $66 Total Coal


CoalF$40 $159 Total Natural Gas Contribution Margin


Natural Gas8%$330 $355 Total Power


PowerChange2005 [1]2006E$ millions

[1] Gross margin excludes non-qualifying hedges and synfuel, includes upstream gas contribution margin; See Appendix

Having walked through each business area, let me now summarize our 2006 gross margin outlook. We expect our gross margin to grow 26% to $752 million. As was the case last year, this is well below the 44% compound annual growth rate we have achieved since 2001, and we’re comfortable that the assumptions in our plan are reasonable. We expect the $154 million of gross margin growth to be comprised of two basic elements:

(1) First, 52% of the $154 million increase is attributable to the increase in 2006 backlog realization, which is up $80 million year-over-year

(2) The remainder of the growth is primarily comprised of increased new business from our Power group and the first full-year of contribution from our upstream and downstream gas operations.

Our track record of solid and steady performance gives us confidence that we can meet this forecast. The successful establishment of our three-commodity platform reduces our exposure to a single commodity market and presents additional opportunities for future growth. We expect another banner year for the Commodities group, and we’re very optimistic about our growth prospects in the years to come.

With that, I’d like to turn it over to Tom Brady …

36

NewEnergy

Thomas F. Brady

Thank you Felix.

And good morning everyone.

It’s been well over 3 years since Constellation made a strategic decision to build a Commercial & Industrial retail competitive supply business.

As we’ve said before, this move was a natural extension within our merchant energy capabilities.


37

37

NewEnergy Load Growth

18Bcf

15Bcf

22Bcf

40Bcf

Electric Acquisition Total = 5,075 MW

45% Annualized Growth Rate 2003 - 2005

+ =

2003 – 2005 Organic Growth 2005

CNE – Electric

15,500 MW10,425 MW

Dynegy – 200 MWNICOR – 400 MW

Blackhawk – 175 MW

ACQUISITIONS

NewEnergy – 4,300

Alliance

132 Bcf

NICOR

EnCa

na Kaztex

Blackhawk + =

2003 – 2005 Organic Growth 2005

CNE – Gas Division

300 Bcf73 Bcf

Gas Acquisition Total = 227 Bcf

10% Annualized Growth Rate 2003 - 2005

Beginning with the acquisition of AES NewEnergy --- combined with a series of companion acquisitions --- and fueled by organic growth ---Constellation NewEnergy has become the leading supplier in the commercial and industrial sector.

When we acquired NewEnergy in September 2002, it was a 4000 MW business.

We made a series of tuck-in power acquisitions, broadened our product base through gas acquisitions, and allowed both businesses to grow organically.

Turning to Slide 38….

38

38

Continued NewEnergy Momentum

Source: KEMA 2005 Retailer Review – September 2005

Continued strength in market share and peak load served

Benefits of Scale:

- Supply & risk management

- Back office costs

- Branding

- Multiple commodity product offerings

- Energy service company capabilities

- Geographic diversity

NewEnergy

Reliant

TXU

Great Plains

SUEZDirect Energy

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2003 2004 2005

MW

From the very start, our strategy was different from then existing marketers. Our hypothesis: Scale matters.

Today, most market participants agree. Scale benefits virtually every aspect of the business

•Supply and risk management

•Lower back office costs

•Branding

•Multiple commodity product offerings

•ESCO capability

•And most importantly, geographic diversity.

Turning to Slide 39….

39

39

Significant Market Presence

• 15,500 MW• 300 BCF

Largest Retailer –• #1 position for electricity• Top 10 position for gas

• Top National Player• 4 Regions 2,000 MW +

- Texas- Great Lakes (IL, MI, &

OH)- New York- New England

• 2 Regions 1,000 MW +- Mid-Atlantic- California

ElectricityNatural GasElectricity and Natural Gas

In the past we have shown this map and said geographic diversityprovides us the North American presence to cross-sell, provide value to national customers, and most importantly, limit our exposure to unfavorable market conditions – or regulatory rules - in any one region.

With sales of 300 billion cubic feet of gas and contracted power load of 15,500 MW, we are the largest retailer in the commercial and industrial sector. This year our load served exceeded 2,000 MW in four regions.

Turning to slide 40….

40

40

2005 NewEnergy Results

• $6.9 Bil of Revenue

• 64 Mil MWh Electric Volume

• 300 BCF Gas Volume

• $274 Mil of Gross Margin

• $2.05 SGA / megawatt hour

• Market Share growth

– 24% Electric

– 4% Gas

61%

45%

8%

2%

3 pts

Performance vs. 2004

19%

Strong growth / Leveraging costsSee Appendix

2005 was a successful year for NewEnergy -

• Electric market share grew by 3 points to 24%

• Megawatt hour sales increased 45%

• SG&A improved by almost 20%

• and in the face of high prices, the Gas division increased sales volumes by 8%.

During the summer, weather drove strong customer demand, high prices and price volatility throughout the country’s power markets, especially Texas. In Texas, we and other suppliers experienced unprecedented load shaping and ancillary costs. Extreme market conditions, coupled with our own regional growing pains, undermined NewEnergy’s gross margin.

Despite this difficult environment, retail gross margin was still comparable to the prior year.

In fact, excluding Texas, we were able to exceed the business plan target for electric gross margin per megawatt hour.

This underscores the importance of our national platform.

Turning to 41…

41

41

Q4 2005 Highlights

Sales activity strong year over year Signed $86M in retail gross margin – 53% increase

119% 117%128%

153%

0%

20%

40%

60%

80%

100%

120%

140%

160%

Rate Term Volume Margin

20042005

During our last earnings call, I mentioned that the 4th Quarter was an important sales cycle for NewEnergy.

I am excited to report it was a tremendous sales quarter. Gross margin from new sales was $86 million, a 53% increase over the contracted margin from the same quarter last year.

This favorable outcome was driven by improvement in all factors of business signed:

• Gross margin per megawatt hour increased 19%

• Contracted volumes increased 28%

• and contract term was 17% longer

The strong sales cycle bodes well for the business in 2006.

Turning to 42…

42

42

Our Customers

®Trademark of The Dow Chemical Company. The DuPont Oval logo is a trademark of DuPont or its affiliates.

Constellation NewEnergy has a customer focused business model. We now count nearly three-quarters of the Fortune 100 as valued customers.

The current price environment underscores the value of our product and services.

We focus on a consultative approach that allows organizations to achieve cost objectives, reduce price volatility and manage risks.

We use the same approach in both the power and gas divisions.

43

43

Customer Satisfaction

Maintained high level given growth and high price environment

93% of NewEnergy customers surveyed are:

– Overall satisfied with NewEnergy

– Willing to renew with NewEnergy

– Willing to recommend NewEnergy

Last year, we once again measured customer satisfaction. For thesecond year in a row, more than 93% of our customers are satisfied. That means they would renew with us and they would recommend us to others. I might add we were able to maintain this high level of satisfaction during a time of rapid business growth and rising prices.

44

44

3947

59 65 6573 79

224

12816 17 20

020406080

100

2002 2003 2004 2005 2006 2007 2008

Th

ousa

nds

of

MW

Switched Market and Market Share Growth

Switched Market CNE Load

• Market share growth expected to exceed projected switched market

• Market share targeted to be between 25-31% over plan period

53%

19%

2002-2005

14%CNE Load

10%Switched Market

2006-2008CAGR

Looking at 2006, we continue to see the electric switched market as a growth market. During the past 3 years, the growth rate has been 19 percent compounded and during that time NewEnergy has grown at a compound annual rate of 53%.

We expect the market growth to continue - - - although at a slower pace, - - -as more businesses become educated on the risk management and cost containment benefits we offer.

We anticipate the North American switched market will grow 7% annually from now to 2008, and 10% from now to 2010. This projection is in line with KEMA’s market projections.

As the switched market grows, our business should grow at least at the same pace in mature markets and faster in newer markets. We anticipate market share will improve from today’s 24% to nearly 30% over the plan period.

Our growth assumptions reflect the regulatory framework currently in place and do not depend on new markets opening to competition.

Turning to Slide 45…

45

45

Volume Growth

61% of 2006 MWh volume under contract

6374

92103

2128

44

64

816

45

0

20

40

60

80

100

120

2002 2003 2004 2005 2006 2007 2008

Mil

lion

MW

h

Plan Contracted Actual Delivered

18%2006 – 2008 Plan

45%2002 - 2005 Actual

CAGRTimeframe

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

We expect volumes to grow at a compound annual rate of 18% over the next 3 years.

Last year we delivered 64 million megawatt hours, slightly more than plan. We plan to deliver 74 million megawatt hours in 2006, a 15% increase over 2005. We presently have over 60% of this under contract –on track with our business plan and comparable to our status at this time in prior years.

Gas sales volumes are expected to be 340 billion cubic feet, a 13% increase over last year. Approximately three-quarters of the volumes are already under contract.

Gas continues to be a strong contributor to our retail strategy.


46

46

Success Breeds Future Successes

• Continue to Build the Brand

• Leverage National Capability

• Optimize Services

– Electricity / Gas / Services cross-selling

• Leverage Scalable Low Cost Model

– Standardize infrastructure and processes– Eliminate competing applications– Increase web services

• Excellence in Customer Service and Creativity

• Integrate Acquisition Opportunities

Well-Positioned Industry Leader

At Constellation, we believe our past success in building scale will breed future success.

Our NewEnergy Companies are the #1 competitive supplier and are well positioned to continue as the industry leader.

Thank you, and now let me turn it over to Follin.

47

Financial Overview

E. Follin Smith

Thanks Tom. Good morning everyone, and thank you for joining us.

Let’s start on page 48…

48

48

Agenda

• Fourth Quarter and Full-Year 2005 Results

• 2006 Earnings Outlook

• Building the Merchant Income Statement

• Capital Expenditures and Cash Flow

• Balance Sheet

• ROIC

• Long-term Earnings Growth Outlook

I will begin this morning with a more detailed look at our fourth quarter and full-year results, as well as our 2006 outlook. I will also spend some time reviewing our capital expenditures, cash flow, balance sheet and return on invested capital. Finally, I will provide some insight into our earnings outlook beyond 2006.

Turning to slide 49 and our fourth quarter results…

49

49

4th Quarter EPS Summary

[1] Excludes special items and certain economic, non-qualifying hedges

(0.02)0.04Special Items

See Appendix

$0.81 - $1.06Q4 2005 Earnings Guidance

51%$0.36$0.71$1.07Adjusted Earnings Per Share [1]

(0.03)(0.06)Gain on Economic Non-Qualifying Hedges

$0.76 $1.09GAAP Earnings

%EPSQ4 2004Q4 2005

Change($ per share)

Fourth quarter GAAP earnings were $1.09 per share. We recognized several special items in the quarter that in total reduced GAAP earnings by 4¢ per share, including 9¢ of merger-related costs and the 4¢ per share negative cumulative effect of FIN 47 adoption for conditional asset retirement obligations, partially offset by the 9¢ gain on the sale of our Panama business in October. Also in the quarter, we had 6¢ of mark-to-market gains related to certain economic non-qualifying hedges. As discussed in our third quarter call, we are calling out the mark-to-market on economic hedges of fuel adjustment clauses and gas transportation contracts that do not qualify for hedge accounting treatment.

After adding back the effect of special items and subtracting the gain on economic, non-qualifying hedges, adjusted earnings per share were $1.07, exceeding our guidance of 81¢ to $1.06 and 36¢, or 51% above our fourth quarter 2004 results.


50

50

4th Quarter Segment EPS [1]


N.M.0.02(0.02)-Other Non-regulated

See Appendix

$0.81 - $1.06Q4 2005 Earnings Guidance

51%$0.36$0.71$1.07Adjusted Earnings Per Share

47%0.080.170.25Utility

46%$0.26$0.56 $0.82Merchant

%EPSQ4 2004Q4 2005

Change($ per share)

In looking at the segments, you can see that it was a strong quarter across the board. On an adjusted basis, the merchant earned 82¢ per share, near the high end of our guidance range of 60¢ to 85¢ per share. Compared to last year’s fourth quarter adjusted EPS of 56¢ per share, merchant earnings were up 26¢. The 46% growth was largely driven by continue strong performance in Wholesale Competitive Supply -- new business grew by 25¢ while backlog realization was up 9¢. We also increased synfuel production, which added 4¢. These positives were partially offset by stock option expense of 4¢ and inflationary and other costs. BGE had adjusted earnings of 25¢ per share, exceeding the top end of our guidance range of 17¢ to 22¢ and up 8¢ over the fourth quarter of 2004. BGE was up compared to last year due primarily due to customer and usage growth and favorable weather conditions.Turning to slide 51…

51

51

2005 EPS Summary [1]

[1] Excludes special items and certain economic, non-qualifying hedges - See Appendix

N.M.0.07(0.06)0.01Other Non-regulated

$3.35 – 3.602005 Earnings Guidance

16%$0.50$3.12$3.62Adjusted Earnings Per Share

15%0.130.881.01Utility

13%$0.30$2.30 $2.60Merchant

%EPS20042005

Change($ per share)

-11¢ Competitive Transition Charge

-11¢ New Energy Texas

-9¢ Inflation (Generation and HQ)

-8¢ Ginna

-6¢ New Energy 2004 Bankruptcy Settlements

-19¢ Other Costs (Dilution, Option Expense, Depreciation, Other)

+33¢ Wholesale Competitive Supply

+30¢ Productivity (Generation and HQ)

+15¢ Interest Expense

+10¢ 2004 CSX Coal Delivery

+ 6¢ Synfuels

Merchant Variance from 2004

For the full year, our adjusted earnings were $3.62 per share, up 50¢ or 16% from last year, and above the top end of our guidance range of $3.35 to $3.60. The Merchant achieved 30¢ growth in adjusted EPS. Earnings benefited from 33¢ growth in Wholesale Competitive Supply, both in new business originated during the year and backlog realized. Successful execution of our productivity initiatives yielded an additional 30¢. Lower interest costs resulting from lower debt and higher cash balances drove 15¢ of gains. You may remember that in 2004 we experienced coal rail delivery problems. We benefited 10¢ as a result of not experiencing a repeat of the 2004 problem. We increased synfuels production which created an additional 6¢ of earnings. Offsetting these items was a loss of 11¢ due to a decrease in CTC revenues. NewEnergy was also down 11¢ in Texas due to pricing volatility and operational challenges. Year-over-year inflation for Generation and HQ cost us 9¢. Ginna was down 8¢ versus the prior year due to dilution associated with the shares to finance the acquisition. We also lost 6¢ due to the absence of favorable bankruptcy settlement payments received by NewEnergy in 2004. Finally, we have an aggregation of smaller unfavorable items including dilution, option expense, depreciation and other costs.The Utility’s earnings were up 13¢ compared to 2004, primarily due to favorable weather.The other non-regulated segment is up 7¢ compared to last year primarily as a result of the acquisition of our energy services business, Cogenex. Turning to slide 52…

52

52

2005 Financial Highlights

• Banner wholesale competitive supply origination

$200$224$318Costs

2005

$504

236

$268

Jan. Targets

[1] Includes power, gas (non-project) and coal gross margin and gas project margin (projected revenue less operating, depreciation, depletion and interest expenses incurred at the project level)

197415Future Year Gross Margin

$398$793Total Originated [1]

$201$378Current Year Gross Margin

2004Actual($ in millions)

Before I turn to the 2006 Outlook, let me pause to reiterate a few of our financial accomplishments in 2005.

Wholesale competitive supply had a banner year. We set out the year with a lofty target for new origination to be up 27% from 2004. In fact, new origination was up 99%, with healthy additions from our prospering coal and gas businesses. The $415 million addition to the backlog provides a solid base of future earnings.

Higher current year gross margin than plan allowed us to add staff and build the business for the future. The bottom line: we achieved our 2005 EBIT plan, built a strong backlog of earnings for the future, and built a more powerful business platform.


53

53

2005 Financial Highlights

($1.12)$4.58$3.46Electric GM/MWh – excluding Texas

($1.89)$4.45$2.56Electric GM/MWh

$0.47$2.52$2.05Electric SGA/MWh[1] Excludes bankruptcy settlements

($22.1)$71.2$49.1Total EBIT [1] ($ in millions)

10.469.980.3All Other [1]

($32.5)$1.3($31.2)Texas

Change Fav/(Unfav)20042005

• NewEnergy Electric growth in most regions

• $90 million in productivity primarily driven by Generation• Debt-to-capitalization improved by 3.7 points from 46.5% to 42.8%

See Appendix

NewEnergy had solid revenue and market share growth in most regions. As Tom discussed, we had growing pains in Texas as did many of our competitors during the volatile period of the third quarter. For some time now, we have indicated our expectation that average realized margins would decline to a level closer to $3.00 per MWh as high-margin contracts roll off. Excluding the effects of Texas, we exceeded our gross margin plan of $3.35 per MWh by 11¢ and delivered over $80 million of EBIT. We also reduced SG&A per MWh by 19% to $2.05 as we leveraged our larger platform. This further bolsters our competitive position for the future.

We delivered $90 million of productivity due to better nuclear outage management, the benefits from our fleet management approach and smart IT management. This means we established a more powerful competitive cost position.

All of this earnings growth was delivered while improving the balance sheet with debt to total capital down from 46.5% to 42.8%.


54

54

Agenda





• Balance Sheet

• ROIC


Now let me turn to our outlook for 2006 starting on slide 55…

55

55

2006 EPS Outlook

1% - 9%

(17%) – (7%)

N.M.0.010.02 – 0.06Other Non-regulated

See Appendix


$3.62$3.65 - $3.95Adjusted Earnings Per Share

1.010.84 – 0.94Utility

$2.60 $2.80 - $3.00Merchant 8% - 15%

% Change2005 [1]2006E($ per share)

For 2006, our guidance range is $3.65 to 3.95, which represents 1 to 9% growth over a highly successful 2005. The merchant will be up 8%-15%, while BGE, which benefited from weather in 2005, will be down.


56

56

2006 EPS Walk

See Appendix

Merchant: Fundamental growth drivers of competitive supply and productivity partially offset by CTC wind-down and other costsBGE: Return to normal weather

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

This chart walks through the factors that will contribute to our 2006 earnings growth. We have used the middle of the guidance range throughout this analysis. As an overview, you see our fundamental growth drivers – competitive supply and productivity – as well as the beginning of the impact of higher commodity prices. These were partially offset by the headwind of the wind-down in our competitive transition charge which we have been expecting.

I will walk you through each of these drivers, starting on slide 57…

57

57

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

2006 EPS Walk – Wholesale Competitive Supply

See Appendix

Wholesale Competitive Supply will be up 43¢ year-over-year. This increase is driven both by a higher backlog of already originated business versus what we had going into 2005 and by an increase in new business net of increased costs to achieve this growth.


58

58

Wholesale Competitive Supply

[1] Includes power, gas (non-project), and coal gross margin and gas project margin (projected revenue less operating, depreciation, depletion and interest expenses incurred at the project level)

26%

$154$598$752Total

$74$378$452Total New Business Realized in Earnings [1]

(31)204173Portfolio Management & Trading

347Coal

7638114Gas

26132158Power

New Business (Originated & Realized)

8023103Hydrocarbon Project Margin [2]

[2] Excludes South Carolina synfuel facility expenses of $19 million in 2005 and $24 million in 2006E

$79$221$300Total Already Originated Business [1]

$ (1)$198$197Power Gross Margin

Already Originated Business


As Felix discussed, wholesale competitive supply is planning to achieve $752 million in gross margin in 2006, representing 26% growth over 2005. $300 million will come from already originated power and hydrocarbon business. This backlog position is $79 million higher than year-end 2004.

The next section of the table outlines our expectation for new business to be originated and realized in 2006. We expect some growth in each of power, gas and coal. Consistent with our past practice, new business growth includes rebalancing of our portfolio through new deals, restructurings and divestitures. Given our focus on deploying capital to achieve above hurdle rate returns, we expect that upstream gas properties we invest in and develop will reach a level of maturity at which our shareholders are better served by selling properties with high percentages of proven, developed reserves to other investors. Part of the growth you see in upstream gas new business reflects this expectation.

As you’ll recall, portfolio management and trading is where we will show the benefits of trading and of enhancing the value of the fleet over the business plan forecast, which is based on actual hedges and market forwards for unhedged elements. Our plan reflects a decline of $31 million in portfolio management and trading, reflecting the prudent planning assumption that the strong trading performance of 2005 will moderate in 2006.

In total, we are counting on new business originated and realized in 2006 to be $452 million, up $74 million, or 20% from 2005. With one month of the year behind us, we feel like this forecast is very achievable. New business originated in January represented attainment of about one quarter of the year’s new business target.


59

59

Wholesale Competitive Supply: Origination

$31

(43)

$74

Change

Total Wholesale Competitive Supply Origination Value to be Realized [1]

[1] Includes power, gas (non-project) and coal gross margin and gas project margin (projectedrevenue less operating, depreciation, depletion and interest expenses incurred at the project level)

415372Future Years

$793$824Total Originated

$378$452Current Year

To Be Realized In:

20052006E($ in millions)

Not only are we counting on $452 million of new origination to be realized in 2006, we are counting on the wholesale group to originate $372 million in margin to be realized in future years. Overall, our 2006 total origination target stands at $824 million, which is up $31 million, or 4%, over a very strong 2005.


60

60

Wholesale Competitive Supply Backlog

300

241

194157

$0

$50

$100

$150

$200

$250

$300

$350

2006 2007 2008 2009

Mill

ions

Note: As of December 31, 2005

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

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


61

61

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

2006 EPS Walk – NewEnergy

See Appendix

Earnings at NewEnergy will be 8¢ higher in 2006 as compared to

2005, as detailed on the next slide, 62…

62

62

NewEnergy

20052006E

7396EBIT [1]

274329Reported GM ($ in millions) [1]

$6.9$10.2Revenue ($ in billions)

- Purchase contract amortization of ($5) million in 2005 and ($4) million in 2006- Consulting and other gross margin in 2005 and 2006- Gross Receipts tax of $39 million in 2005 and $57 million in 2006- Bankruptcy settlements of $1.5 million in 2005

[1] Reported Gross Margin and EBIT include the following, which have been excluded from statistics:

$0.09$0.09SG&A / Dth$0.17$0.15GM / Dth

300340Gas (millions of Dth)

$2.05$1.90SG&A / MWh$2.56$2.90GM / MWh64.273.8Electricity (millions of MWh)

Statistics [1]

See Appendix

We expect NewEnergy’s EBIT to increase about $23 million from 2005 levels. Electric and gas volume growth will be strong but moderate somewhat versus historic growth rates reflecting the market dynamics caused by the high price environment. Based on already booked business combined with recent origination levels in the $3.00 area, we expect average realized gross margin to be approximately $2.90 per MWhr, reflecting some hangover from the 2005 Texas issue. SG&A costs per unit will continue to decline as we streamline processes and systems and leverage our growing volumes. In total, higher market shares and continued volume growth, stabilizing realized margins, and cost leverage should drive good EBIT growth.


63

63

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

2003 2004 2005 2006 2007 2008

Actual / Forecast Realized EBIT Margin

EBIT Margins on New Sales at $3.00

Growing NewEnergy EBIT Margins / MWh

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

2003 2004 2005 2006 2007 2008

Actual / Forecast GM/MWH Margins indicated by new sales

Actual / Forecast SGA/MWH

New sales over past 24 months continue to support $3.00 GM / MWh prediction

Declining SG&A / MWh drives growing EBIT Margins / MWh

Gross Margin and SG&A/MWh EBIT/MWh

We have been telling you for sometime that when we bought NewEnergy, a portion of its load serving contracts were unhedged. Power prices had declined since these contracts were signed. We hedged the contracts at lower prices post-acquisition. This phenomenon has resulted in high realized gross margins per unit in 2003 through 2005, represented in the left box by a red line.

New sales levels in 2004 and 2005 represented by the blue line have supported our expectation that this is a $3.00 per megawatt hour gross margin business.

When you combine stable new sales gross margins per megawatt hour with declining SG&A costs per megawatt hour, our outlook is for growing EBIT margins per megawatt hour over the remainder of thebusiness plan time horizon.


64

64

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

2006 EPS Walk - CTC

See Appendix

The end of the residential price freeze service this summer on our merchant fleet will drive an added 10¢ per share compared to 2005. This will be offset by a decrease in competitive transition charge revenues. For several years, we have been projecting for you how the roll-off of the Maryland competitive transition charge will affect our 2006 year-over-year comparison. The collection period for residential CTC ends on June 30, 2006. We expect a 22¢ unfavorable effect versus 2005, reflecting one half-year of CTC payments. The final impact will be in 2007, the first full-year in which CTC is fully phased out.


65

65

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

2006 EPS Walk – Productivity, Inflation

See Appendix

For 2006, we expect productivity to drive an additional 13¢ of year-over-year earnings growth, in line with what we outlined for you lastyear. This will more than offset 10¢ of inflationary cost increases at headquarters and generation.

Turning to slide 66..

66

66

Generation: 2006 Highlights

• Productivity Initiatives

– Power uprate at Ginna of 83 MW to 581 MW

– Shortened refueling outage at Nine Mile Point

• Calvert Cliffs Reactor Vessel Head Replacement

• UniStar – New Nuclear Initiative

– Joint venture with AREVA, Inc.

– One-stop-shop to design, construct, license and operate standardized fleet of advanced nuclear plants

– Plan to form joint ventures for each nuclear power plant

– Modest costs in 2006

Before we go into the specifics of this year’s productivity goals, I’d like to take a minute to highlight our Generation Group’s 2006 initiatives. As you all know, the Generation Group is the primary driver of our goal to improve earnings by $150-$180 per year through a multi-year productivity initiative. Better nuclear outage management and benefits of our fleet management approach drove productivity improvements above our plan for 2005, and there is more to come in 2006. This year, Nine Mile Point will continue the march toward top quartile performance. We will also complete an 83 MW uprate at Ginna that will position us for further productivity gains in 2007.We will replace a reactor vessel head at Calvert Cliffs in 2006. Although this will increase our outage days and costs versus 2005, this will support our long-term efforts to maintain that facility as a top decile performer.In the third quarter, we announced a joint venture with AREVA to develop and deploy the first fleet of advanced nuclear power plants in America. As envisioned, we will form joint ventures for each nuclear power plant in which CEG may participate as an operator and/or as an investor. Until we identify a specific project or commit to ordering advance materials for a new nuclear power plant, Constellation’s financial commitment will be limited to the costs of forming the business platform, funding business development activities, and early licensing activity. Moving to slide 67…

67

67

Productivity Definition

Equals:

Less:

Plus:

Plus:

Less:

Productivity

(e.g. extraordinary maintenance)

Expense timing items that swing from year to year

Impact of D&A from spending on productivity initiatives

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

EBIT increases driven by structural plant output increases

Increases due to general inflation and benefits inflation

Change in Generation and Headquarters O&M

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

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

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


68

68

CumulativeProductivity Gains (2004 - 2008)

($40)

$50

$90

$150

($100)

$0

$100

$200

2004A 2005A 2006E 2007E 2008E

$150 - $180

Productivity

• In 2004, indicated pre-tax productivity target of $150 - $180 million from 2003 to 2008

• Productivity gains should drive approximately 2% EPS growth through 2008

Cumulative impact ($/share): ($0.14) $0.18 $0.32 $0.53 $0.53-$0.64

This chart shows the cumulative productivity gains that we are expecting through 2008. As you’ll recall, in 2004 we promised that 2008 pre-tax earnings would be $150-$180 million higher than 2003’s due to productivity initiatives. We exceeded our $80 million productivity target for 2005 by $10 million, and are poised to reach our 2008 goal, which will drive approximately 2 percentage points of EPS growth each year on average through 2008.


69

69

Productivity

33Cost Productivity

18Extraordinary Maintenance/Other

$40Total 2006 Productivity

$9352005

9532006

(18)Change in Operating Expenses

Less:

33Inflation

7Gross Margin Productivity

Generation and HQ Operating Expenses

Favorable/ (Unfavorable)($ in millions)

• CEG EBIT $40 million higher in 2006 than 2005 due to productivity initiatives• 2006 EBIT $90 million higher than 2003 due to productivity program

In targeting our incremental productivity gains for 2006, we will continue the initiatives that we began in earnest in 2004. Our fleet management strategies will leverage the best practices of Calvert Cliffs to Nine Mile Point, shortening outages and reducing costs associated with labor and materials. Calvert itself will continue to march to better performance. In total, we expect 2006 EBIT to be $40 million higher than 2005’s due to these initiatives. The cumulative impact of these programs will have raised the company’s EBIT by $90 million comparing 2006 to 2003.


70

70

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

Other

See Appendix

We expect to see a negative 16¢ variance which reflects an accumulation of smaller items.


71

71

Other

-11¢ Decommissioning Liability Accretion / New Nuclear Initiative / Other

-3¢ Synfuels

-7¢ Planned Outages+5¢ Other Non-Regs

UnfavorableFavorable

Other non-regulated businesses should be up 5¢ year-over-year primarily driven by the discontinuation of our building services business.

On the unfavorable side, at the bottom you see an aggregation of small items including the scheduled increase in the accretion of our nuclear decommissioning liability and spending on new nuclear initiatives. I want to touch on 2 items, 7¢ of planned outages and 3¢ of synfuels, discretely.


72

72

2006 Planned Outages

($20)

(16)

10

($14)

($ in millions)

Planned Outage Impact

Extraordinary fossil maintenance

Primarily absence of 2005 Brandon Shores outage to replace cooling tower

Nuclear Outages: Primarily Calvert Cliffs in 16 days longer outage for R.V. head replacement

Timing effect of planned outages is (7¢) in 2006

For 2006, planned outages will drive a 7¢ year-over-year decline in EPS. Nuclear outages will drive a $14 million negative pretax variance, driven primarily by the replacement of the Calvert Cliffs Unit 1 reactor vessel head, which will add 16 days to the outage and create higher removal costs, which are treated as O&M expense. We have been planning this RV head replacement for a number of years and have very detailed plans to execute the outage crisply.

We have a favorable pre-tax variance of $10 million gross margin primarily due to the absence of a 2005 Brandon Shores outage to replace a cooling tower.

Finally, we have more outages in our fossil fleet to perform a number of planned extraordinary maintenance items, which will cost us $16 million more pre-tax in 2006 compared to 2005.


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73

Extraordinary Maintenance

2.88.4(3.2)11.28.0Wagner

$8.6$1.9($7.2)$10.5$3.3High Desert

$11.7$32.9($16.0)$44.7$28.8Total

(2.4)8.8(2.1)6.54.5Others

3.17.3(1.7)10.48.7Brandon Shores

(0.4)6.5(1.8)6.14.3Crane

O&M Expense

’06-’07 Change2007

’05-’06 Change20062005

20072006($ in millions)

Extraordinary maintenance is any significant maintenance activity (non-baseline) not performed every year

Extraordinary Maintenance is any significant fossil plant maintenance activity not performed every year, like turbine and boiler inspections. Extraordinary maintenance is done at the optimum point in each plant's life and can cause lumpiness in our maintenance schedules and earnings.

In 2006, we will perform significant work at High Desert, Wagner, Crane and Brandon Shores, which will increase our 2006 pre-tax O&M expense by $16 million or 5 cents per share. This will essentially reverse in 2007 when we expect to spend $11.7 million or 4 cents less on extraordinary maintenance compared to 2006.

Turning to slide 74...

74

74

Synfuel

Year-Over-Year EPS Impact

$62Net Income Post Phase-out

-Phase-out Risk – 12/15/05

62Net Income Pre Phase-out

115Tax Credits

32Tax Benefit of Pre-tax Loss

$(85)Pre-tax Loss Change of Production

2005($ in millions)

$0.04$(0.03)

$63$56

(18)(23)

8179

141139

3637

$(97)$(97)

20072006

7Net Impact

45Long Oil-Correlated Positions

(38)Synfuel Phase-out (Pre-tax equiv.)

2006

149636415

216636444

(67)--(29)

Total2009+20082007

Change in Synfuels and Long Oil-Correlated Positions (12/04 – 12/05)

Risk to 2006 with Synfuels Tax Credit Phase-out; Rising Oil Prices Overall Positive to CEG

One topic I should discuss is synfuels. It’s not driving much of a year-over-year variance, but it coulddepending on oil prices.

We have stepped up synfuels production in our plan at both of our facilities. This would drive a 10¢ year-over-year favorable impact in the absence of tax credit phase out risk. We think increased production makes economic sense as long as expected tax credits exceed the net variable cost of production. The break-even is in the area of 60-70% tax credit phase out. A phase out of less than this would still allow us to generate positive after tax earnings and cash flow from producing and selling synfuels.

In our 2006 forecast, we have a assumed 17% or $23 million tax credit phase-out based on oil price forwards as of December 15, when we set the plan pricing.

Obviously, the risk of the phase out will move with oil prices. We have told you we hedge the tax credit phase-out risk along with our other fuel positions as a portfolio. Essentially, we view the synfuel tax credits as a short oil position and we have a portfolio of other long oil-correlated positions which serve as a hedge. What you see in the chart at the bottom provides a bit of a window into what has happened and what could happen. Between December of 2004 when last year’s business plan was completed and December 15th, 2005 when this plan was completed, our estimated loss of tax credits due to phase out is $67 million cumulatively for 2006 and 2007. That is, as oil prices have gone up, we value the risk of tax credit phase out at $67 million pre-tax. On the other hand, our portfolio of long oil-correlated positions gained $216 million in value and by much more than the impact of the synfuel tax credit phase-out.

I point all of this out to you to emphasize that this year’s EPS may decline from that presented today if oil prices stay at levels above the 12/15 level. Oil prices have increased since we set our plan at 12/15. Market forwards and volatilities as of Friday, January 27 would indicate an approximate 55% tax credit phase out. When netted against a small favorable 2006 impact of the long oil-like positions, this would reduce our 2006 EPS by approximately 24 cents compared to the numbers included in this presentation. On the other hand, the implied rise in energy prices would likely be very good news for the long-term value of Constellation Energy, due to the implications for the value of our baseload fleet as well as our long oil positions.


75

75

(0.10)

(0.22) 0.10

0.16

0.27

0.08 0.13

3.62

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

2006

Comp.

Transition

Charge

2005

Inflation

HQ &

CGGProductivity

HQ & CGG

Wholesale

Comp. Supply

Backlog BGE

(0.08)

(0.16)

3.65 - 3.95

Other

Wholesale

Comp.

Supply New

Business

NewEnergy

Fleet Price

2006 EPS Walk - BGE

See Appendix

BGE’s contribution will be 8¢ lower in 2006 versus 2005.


76

76

BGE Rate Case Summary

• BGE filed a gas distribution rate case on April 29, 2005– First rate case filed in six years

• Final rate order increasing rates by $35.6 million went into effect on December 23, 2005

8.5%Return on Rate Base

48%Equity Ratio

11%Return on Equity

$36Rate Increase (millions)

$794Gas Rate Base (millions)

Final Order

As you will recall, BGE filed a gas distribution rate case on April 29, 2005, which was our first rate case filing in six years. The final order, which became effective on December 23, granted a rate increase of about $36 million based on an ROR of 8.5% and ROE of 11.0%. We are very pleased with the work that was done by the utility and believe the PSC ran an efficient and fair process.


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77

2006 BGE Walk

4 120116Income Tax

$(11)$404$393EBIT

(6)161167Other Expenses

2 232230D & A

[1] Represents mid-point of guidance range

($0.08)$1.01$0.93Adjusted EPS [1]

($12)$182$170Net Income

01313Preferred Dividends

(5)8994Net Interest Expense

(28)456484O & M

36 285321Gas Gross Margin

See Appendix

$21$1,253$1,274Gross Margin

($15)$968$953Electric Gross Margin

Change20052006E [1]($ in millions except per share data)

Major Variance Drivers vs. 2005: +12¢ Gas Rates -8¢ Electric GM primarily weather -15¢ O&M and Other Expenses+6¢ POLR -3¢ CTC

BGE gross margin will be higher by $21 million in 2006, primarily due to increases in gas rates from the rate case, and due to higher POLR volumes. As the six-year price freeze ends for residential customers on June 30, and as customers transition to market based rates, BGE will serve as the provider of last resort for which it will earn a mark-up, driving a $17 million increase in gross margin. The POLR margin is intended to encourage competition in Maryland and to compensate BGE for its role. Electric distribution gross margin is otherwise forecast to be down $22 million or 8¢ per share as we assume normal weather patterns in 2006 versus the extreme conditions in 2005. Finally, CTC roll-off will reduce BGE’s gross margin by 3¢ as we expected.

For 2006, we have increased expenses of $37 million: 5¢ for inflationary and pension assumption changes, 3¢ for spending on reliability, 2¢ attributable to increased uncollectibles as commodity prices and bills rise, and 2¢ for additional interest expense as BGE borrows more to fund an increased capital program. Taxes, dilution and other items account for the remaining 3¢.

The resulting EPS will be 93¢ per share, down 8¢ from a strong 2005 and in-line with a more normalized 2004.


78

78

Agenda





• Balance Sheet

• ROIC


Now I’d like to provide a look into the merchant income statement. The information in this section is designed to help you with building your model, and should be used in conjunction with the additional modeling information in the back of the presentation.

First, the Merchant business on slide 79…

79

79

Merchant Business

$185$598$783Wholesale Competitive Supply [2]

55274329NewEnergy

[1] Represents mid-point of our 2006 guidance range

(14)753739Plants with PPAs

$197

(4)1713Qualifying Facilities / Other

See Appendix

[2] Gross Margin includes South Carolina synfuels facility expense of $19 in 2005 and $24 in 2006E

$2,478$2,675Total Merchant Gross Margin

836812Mid-Atlantic Fleet (24)

Change20052006E [1]($ in millions)

In total, we expect merchant gross margin to be roughly $2.7 billion, up nearly $200 million, or about 8% from 2005. We have talked about Wholesale Competitive Supply and NewEnergy. Let me give you some background on what we have labeled “Mid-Atlantic Fleet” here. We know you want to understand how much we make from selling the output of the Mid-Atlantic fleet. In reality, the commodities group manages the output of these plants along with all other PJM competitive supply activity in one regional portfolio, in order to optimize the value. That’s part of the strength of our integrated business model. Here we have taken our PJM regional portfolio gross margin, subtracted out notable competitive supply deals not off the fleet to approximate the Mid-Atlantic fleet’s gross margin. The gross margin associated with the Mid-Atlantic fleet is approximately $812 million for 2006, which is a decrease of $24 million over 2005. This decrease is due to lower CTC revenue, which was partially offset by an overall fleet price increase in the second half of the year due to the end of BGE’s 6-year residential price freeze.

We expect Plants with PPA’s will be down $14 million due to the end of a PPA on University Park.


80

80

Merchant – Below Gross Margin

$468

[2] Earnings excluding special items and certain economic, non-qualifying hedges

[1] Represents the mid-point of earnings guidance range

29%(28)(96)(124)Income Tax

13%$ 73 $564$637Pre-tax Income

5%8(164)(156)Net Interest Expense

26%(36)(136)(172)Other Revenue & Expenses

11%(33)(294)(327)D & A

5%(63)(1,320)(1,383)O & M

See Appendix

10%$ 45$513Net Income

9%$ 65$728$793EBIT

8%(132)(1,750)(1,882)Total Costs Below Gross Margin

8%$ 197$2,478$2,675Gross Margin

%$2005 [2]2006E [1]

Change($ per share)

In total, at the midpoint of the guidance range, we expect Merchant gross margin to be up 8% and Merchant EBIT to grow $65 million or 9%. Lower debt balances will decrease interest expense. After-taxes, we project Merchant net income growth of 10% at the mid-point of the guidance range.


81

81

Connecting the Dots

($327)2006 D&A [1]

(33)Change(2)Other(5)Headquarters(7)Commodities

(19)Upstream Gas Depletion/Depreciation

($294)2005 D&A

($1,383)2006 O&M [1]

(63)Change(7)Other

(16)Fossil Extraordinary Maintenance(33)Generation/Headquarters Inflation

27Merchant O&M Productivity(13)NewEnergy Cost to Drive Growth

($21)Commodities Cost to Drive Growth($1,320)2005 O&M

[1] Represents mid-point of the guidance rangeSee Appendix

Year-over-year, O&M expenses are projected to increase $63 million. Commodities and NewEnergy will add about $34 million to their cost bases to drive top-line growth. For generation and headquarters, productivity will largely offset the relentless effects of inflation in 2006. Extraordinary maintenance will drive costs up in 2006, which as I discussed before is a timing item which should reverse in 2007.

D&A will be up $33 million. Most notable is the forecast of gasdepletion which reflects amortization of our gas investments with production.

82

82

Agenda



• Building the Income Statement


• Balance Sheet

• ROIC


Let’s now review our capital expenditures and cash flow.


83

83

Capital Spending

261390398120Change

1070944945912Prior Plan

132141137130Nuclear Fuel

$ 496 $ 389$ 235$ 183Generation Plants

412447367291Utility Total

$ 913$ 879$ 953$ 709Merchant Total

682332Other Non-regulated Business Total

109154187165Technology & Other

$1,331$1,334$1,343$1,032Total Capital Expenditures

176195394231Commodities Group Portfolio

Transactions & Gas Invest.

Merchant

2008E2007E2006E2005($ in millions)

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

You see an increase from 2005 levels of spending to 2006-2008 for generation. This primarily relates to environmental spending, on which I will elaborate in a moment. You see an increase in Commodities Group investments which reflects a placeholder for gas investments to support our successful gas efforts. The utility plans to increase its level of capex over the next two years to invest in reliability. Turning to slide 84…

84

84

Environmental Capex

41 558223221711/05 Projections

1 (182)23(89)(119)Change

$40

1

25

$14

2006

116153145Keystone FGD

$504 $118$242$130Brandon Shores FGD

$740$200$310$190Total Envir. Capex

120673715Other

Total2009-1020082007($ in millions)

Note: Excludes capitalized interest

Last January we projected environmental spending of $100 millionthrough 2007, with an additional $400-500 million more through the end of the decade. We think the capital cost of environmental compliance in this decade will be $180 million higher than the January 2005 projections and that we will start to spend earlier. The numbers shown here reflect scrubbing our biggest coal units, Brandon Shores and Keystone. As Mayo mentioned, Maryland’s rules have not reached full maturity yet, but based on what we know, we do not expect spending to change materially from levels shown here.


85

85

2006E Consolidated Cash Flow

4720027Asset Dispositions & Contract Restructuring

(25)(29)(30)34Working Capital & Other

252221Pension Adjustment (pre-tax)

750(1,343)

10(22)

244(367)

496 (954)

Depreciation & AmortizationCapital Expenditures & Investments

($118)Net Cash Flow before Debt Issuances/(Payments)

(266)Dividends

$148($8)$19$137Free Cash Flow

($593)($12)($123)($458)Net CapEx

$694$11$170$513Net Income Before Special Items

TotalOther

Non-RegUtilityMerchant($ in millions)

See Appendix

Bringing the earnings and capital picture together, in 2006 we expect to generate $148 million of free cash flow. As you can see, the Merchant continues to be a cash flow generator. Because we are investing in reliability at the utility, BGE’s contribution to cash flow will be less in 2006 than in the past.

After dividends, cash flow will be about $120 million negative reflecting our investment in the business combined with the payment of $266million in dividends.

86

86

Agenda





• Balance Sheet

• ROIC


We take a look at the balance sheet on slide 87…

87

87

2006E Balance Sheet

41.6%42.8%46.5%54.6%Comparable Debt to Total Capital

41.6%42.8%46.5%53.5%Debt to Total Capital

0.10.10.10.150% Trust Preferred

Capital

$4.0$3.9$4.5$4.9Net Debt

5.65.15.04.1Equity [1]

(0.7)(0.8)(0.7)(0.1)Less: Cash

$9.7$9.1$9.6$9.2Total Capital

$4.7$4.7$5.2$5.0 Total Debt

1.1High Desert on Balance Sheet

Debt

YE 2006EYE 2005YE 2004YE 2001($ in billions)

[1] Note: Includes FAS 87 Minimum Pension Liability charge / (credit) to equity of $45 million in 2001, $43 million in 2004 and $77 million in 2005. Includes preferred stock & minority interest.

See Appendix

Since 2001, we have reduced the net debt-to-total capital by almost 12 percentage points while growing the business at the same time. Reported net debt to capital at the end of the year was 42.8%, which is slightly higher than plan of 42%. We executed on the key components of our plan such as paying down debt and generating and building strong cash balances. The shortfall to the plan of 42% was primarily driven by accounting items which we do not think make sense to directly manage. Equity balances were down $330 million for two such items: first, AOCI was down $250 million primarily due to the effect of increases in commodity prices on PJM load serving positions. These contracts have to be marked-to-market through Accumulated Other Comprehensive Income, while the offsetting increased generation value will not be realized anywhere in GAAP accounting until power is delivered, resulting in a timing mismatch on the balance sheet. We also had an increased Pension Minimum Liability Charge of $77 million due to the impact of lower interest rates on the liability and the new SEC mortality table requirements. We continue to target a net debt-to-total-capital of 40% for the stand-alone company and will be very close in 2006 as the equity balance grows.


88

88

Agenda





• Balance Sheet

• ROIC


Let’s now review our Return on Invested Capital.


89

89

Return on Invested Capital

6%

7%

8%

9%

10%

11%

2003 2004 2005 2006E 2007E 2008E

Total Company ROIC

’03-’05 Actual / Current ’06-’08 Projections

Prior Year Projections

WACC

Our view as a management team is that we should be making investments which exceed the appropriate cost of capital for the risk specific to each investment. On an aggregate basis, we think its important to track our Return on Invested Capital relative to our cost of capital. As we discussed last January, the company had an average ROIC of 6.5% in 2002. With the success of our operations in 2003 and 2004, we increased ROIC to 8%. As we look around the industry, we think we improved from a sub-par ROIC to one that is superior relative to our cost of capitaland to others in the industry. We got there through smart investments like Ginna and NewEnergy, the smart deployment of capital by our Commodities Group and by eliminating marginal investments like Guatemala and Senior Living Facilities.

In 2005, we exceeded the projections for ROIC we shared with you in January by increasing income with smart investments in our gas business and by selling businesses which were worth more to others than to us such as Oleander and Panama. As you can see, in 2006 and beyond, we are improving our projected ROIC by making smart tradeoffs with your capital. As you'll see on the next chart, the projections for 2007 buybacks are down from what we shared with you a year ago. As we explained was our goal, we have found smart investment opportunities where the returns are superior compared to the risks and improved the return you can expect on capital employed in Constellation Energy.

90

90

Agenda





• Balance Sheet

• ROIC


Now let me spend the last few minutes focusing on our earnings expectations beyond 2006.


91

91

2006-2007 EPS

See Appendix

(0.13)

(0.09)

0.10

0.89

0.060.230.10

$2.75

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

$4.75

$5.00

$5.25

$5.50

2006 2007

Competitive

Supply

Mid Atlantic

Fleet

Competitive

Transition

Charge

Productivity

HQ & CGG

Inflation

HQ &

CGG

Buyback &

InterestBGE

4.75-5.00

28% Growth Rate

3.65-3.95

(0.08)Other

Mayo reaffirmed our 2007 EPS guidance of $4.75 –5.00. This represents a growth rate of approximately 28% off the midpoint of our 2006 guidance. Let me focus on the growth drivers to show how solid this outlook is. The two biggest drivers reflected here are Mid-Atlantic Fleet and productivity. The fleet will experience the biggest impact associated with the end of the Maryland residential price freeze service in 2007. As you will recall, we had set revenues in 2000, but did not hedge fuel costs until much later at higher levels, resulting in artificially low margins on the Mid-Atlantic Fleet. The Fleet is now highly hedged in 2007.

Our productivity results in 2007 will be the result of labor cost reductions already being planned at Nine Mile Point and the gross margin impact of the 2006 83 MW Ginna uprate. Interest cost reductions account for relatively modest 7¢ in these projections. We have also included a modest 10¢ here for Competitive Supply – not because we expect growth to slow meaningfully in 2007 – but rather to demonstrate how solid the building blocks for a $4.75-$5.00 2007 EPS are for a stand-alone CEG.

Finally, at BGE, you see the impact of spending on reliability and inflationary cost pressures.


92

92

Long-term Growth: An End-Game Player

Expiration of hedges established in 2004 and early 2005 for 2006-2007 imply growing 2008 and 2009 margins; 50% nuclear output coupled with today’s higher energy pricing

Repricing of the Fleet

Specific targets, detailed plansPattern of executionProductivity

Generate strong cash flowInvest in above hurdle rate projectsIf none identified – return cash to shareholders as possible

Reinvestment of Cash Flow

Realistic switched market growthModest market share gainsRenewal rates at historical levels

NewEnergy Growth

Already originated businessPattern of building backlogModerating new business growth

Wholesale Competitive Supply Growth

2008 EPS to be 10%-15% above 2007 EPS

The scale and scope of our Wholesale and Retail Competitive Supply businesses continue to have a superior customer proposition which should drive continued growth. Our productivity initiatives are powerful. We’ve executed the 2005 plan as promised, to permanently reduce our cost position and solidify our future competitiveness. We believe there is more to come from streamlining our processes.

We generate strong cash flow, which we will redeploy for the future benefit of our company and our shareholders, or we will return it to our shareholders.

Finally, as we discussed in August, the current high price environment continues to have favorable implications for the value of the fleet in 2008 and 2009. Hedges we established for 2006 and 2007 in earlier years will roll off and are replaced with power contracts reflective of more recent power prices.

Our outlook for 2008 continues to strengthen with rising commodity prices and the growing hedged profile of our fleet. While we will lose synfuels at the end of 2007, we will see gains on the oil-correlated positions I described and we anticipate that the Mid-Atlantic Fleet’s gross margin should add 70-75¢ per share in 2008. When combined with conservative assumptions for our growth drivers of competitive supply, productivity and cash redeployment, we are comfortable indicating now that 2008 EPS should be 10-15% above 2007 EPS on a standalone company basis.

Now let me wrap up on slide 93 with our first quarter guidance…

93

93

Q1 2006 Guidance

$0.71

(0.01)

0.40

$0.32

Actual Q1 2005

See Appendix

(0.01) - 0.01Other


$0.53 - $0.68Adjusted Earnings Per Share [1]

0.38 - 0.43BGE

$0.12 - $0.27Merchant

Guidance Q1 2006($ per share)

We expect first quarter earnings to be 53¢ to 68¢ per share, which compares to adjusted earnings per share of 71¢ in the first quarter of last year. Wholesale Competitive Supply will be up year-over-year as we have higher backlog going into the first quarter than we had in last year’s first quarter and we have strong new business results quarter-to-date. This will be offset by the fact that the Mid-Atlantic fleet is still selling power to BGE residential customers under price freeze service established in 1999, while associated variable costs of generation – coal, oil and emissions – are up. Finally, CTC revenues will be down in the quarter.

We expect BGE and the other non-regulated segment to be about in line with first quarter of last year. That concludes my remarks. Now I will turn it back to Mayo for comments on the merger.

Merchant Story vs Prior Year Quarter

Wholesale Competitive Supply Backlog (pre-existing contracts 0.16 Wholesale Competitive Supply New Business (0.08) Mid-Atlantic Fleet - CTC (0.05) Mid-Atlantic Fleet - Other (0.16) Synfuels 0.03 Other (Corporate Depreciation/Dilution) (0.03)

(0.13)


Wholesale Competi tive Supply Backlog (pre-existing contracts 0.16 Wholesale Competi tive Supply New Business (0.08) Mid-Atlantic Fleet - CTC (0.05) Mid-Atlantic Fleet - Other (0.16) Synfuels 0.03 Other (Corporate Depreciation/Di lution) (0.03)

(0.13)


Wholesale Competi tive Supply Backlog (pre-existing contracts 0.16 Wholesale Competi tive Supply New Business (0.08) Mid-Atlantic Fleet - CTC (0.05) Mid-Atlantic Fleet - Other (0.16) Synfuels 0.03 Other (Corporate Depreciation/Di lution) (0.03)

(0.13)


Wholesale Competitive Supply Backlog (pre-existi ng contracts 0.16 Wholesale Competitive Supply New Business (0.08) Mid-Atlanti c Fleet - CTC (0.05) Mid-Atlanti c Fleet - Other (0.16) Synfuels 0.03 Other (Corporate Depreciation/Dilution) (0.03)

(0.13)

94

Merger Update

Mayo Shattuck

Thank you, Follin.

95

95

Summary• Merger creates new FORTUNE 100 company and the U.S. market leader in

competitive energy markets

• Well-matched, complementary contributions from two strong companies create a balanced footprint

• Multiple channels of growth, balanced by solid base of stable, growing earnings and cash flow from two outstanding state-regulated utilities

• Combined company will have the strongest balance sheet in the industry

• Shareholder synergies expected to be at least $200 - $250 million pre-tax by third year of combination

• Significant increase in dividend for Constellation’s current shareholders

– Generation assets in NEPOOL and ERCOT– Strong wind position– Strong nuclear capability– Focus on cost and operational efficiency

– Highest load serving market share– Leading risk management expertise– Strong nuclear capability– Focus on cost and operational efficiency

FPL GroupConstellation Energy

You all know about Constellation’s most exciting news of 2005—the announcement of the Constellation / FPL merger. The combined entity will also be well-positioned to be an end-game player in a consolidating industry. Neither company needed to do a deal to be successful. Independently, we each have very compelling growth prospects.

In the combination, we are bringing together two of the strongest and most successful companies in the industry. The combined company will be a FORTUNE 100 company, the U.S. market leader in competitive energy markets and the #1 U.S. power generator.

Each company brings excellence in different ways to this combination. Constellation Energy brings the highest customer-facing competitive supply market share and best risk management platform in the business, but has limited generation capacity in NEPOOL and ERCOT. FPL Group has meaningful deregulated generation in these markets, but a smaller load serving business relative to the size of its generation.

This new platform will provide multiple channels of growth, primarily in the deregulated markets. This growth is balanced by a solid base of stable and growing earnings and cash flow from two outstanding state-regulated utilities.

The combined company will also have the strongest balance sheet in the industry, which is valuable in supporting the growth of the competitive businesses.

This growth will be further enhanced by meaningful synergies. The vast majority of these will come from the competitive energy side, but there will be long-term benefits for the utility, too, both for shareholders and for customers. We are very confident that we will be able to deliver at least $200 to $250 million per year of pre-tax synergies retained for shareholders before costs to achieve by the third year of the combination.

Finally, as I mentioned in my opening remarks, our plan is to maintain the FPL Group dividend in effect at the time of closing. After effecting the share exchange, this will result in a significant dividend boost for Constellation Energy’s current shareholders.

96

96

Transaction TimelineQ4 2005 Q1 2006 Q2 2006 Q3 2006 Q4 2006

Announce Transaction

Make Regulatory Filings

File Joint Proxy Statement

Develop Transition Implementation Plans

Receive Regulatory Approvals

FPL Group & Constellation Energy Shareholder Meetings Close Transaction

Major regulatory filings– Nuclear Regulatory Commission– Maryland Public Service Commission – Federal Trade Commission / Department of Justice– Federal Energy Regulatory Commission– Florida Public Service Commission (Notice Only)– Securities and Exchange Commission

Filed in January 2006

So lastly, let me give you an update on where we are with the transaction timeline. We completed our filings with the Maryland Public Service Commission and the NRC in January. We plan to make the remaining regulatory filings and to file the joint proxy statement with the SEC in the first quarter. Overall, we expect to obtain the necessary regulatory approvals and close the transaction in 2006.

With that, we thank you for staying with us for this extended call, and we are ready to take your questions…

97

Question and Answer

All

98

Additional Modeling Information

99

99

Constellation Generation Group Asset Portfolio(11,856 MW as of December 2005)

Calvert Cliffs1,735 MW

Nuclear

Nine Mile Point1,561 MW Nuclear

Sunnyside (QF)26 MWWaste Coal

Rocklin (QF)12 MW, BiomassChinese Station (QF)10 MW, Biomass

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

12 MW, BiomassPoso (QF)

17 MW, CoalJasmin (QF)17 MW, Coal

ACE(QF)32 MW, Coal

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

High Desert830 MWCombined Cycle, Gas

Rio Nogales800 MW

Combined Cycle, Gas

Holland Energy 665 MW

Combined Cycle, Gas

University Park300 MW, 6 CTs,Gas

Big Sandy300 MW, 6 CTs,

Gas

Handsome Lake250 MW, 5 CTs, Gas

Panther Creek (QF)42MW, Waste Coal

Safe Harbor (EWG)278 MW, Hydro

Colver (QF)28 MWWaste CoalKeystone (EWG)

356MW, Coal2 MW OilConemaugh

(EWG)180 MW, Coal

1 MW Oil

Wolf Hills250 MW, 5 CTs,

Gas

Baltimore Plants3608 MWCoal, Gas, Oil

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

131 MW Gas/Oil (1)397 MW Oil (4)14 MW Oil CT

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

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

127 MW Gas/Oil CT (6)

44 MW Oil CT (7,8)Westport 5 121 MW Gas CTPhiladelphia Rd. 1-4 64 MW Oil CTNotch Cliffs 1-8 128 MW Gas CTPerryman 1-4, 51 208 MW Oil CT (1-4)

152 MW Gas/Oil CT

Soda Lake (QF)7 MW, Geothermal

Malacha (QF)16 MW, Hydro

A/C Fuels

Gary PCI

PC V. I

PC WV. I

PC WV. II

PC WV. III

States’ Electric Retail Access Status Legend

Restructuring Not Active

Restructuring Delayed

Restructuring Active

Restructuring Suspended

Restructuring Repealed

Source: EEI Website

R.E. Ginna 498 MW Nuclear

Eastern Plants

Western PlantsNuclear Plants

Fuel Processing Plant

HARFORD COUNTY

BALTIMORE COUNTY

BALTIMORE CITY

Monument St.

Pumphrey

Greene St.

Center

Windy Edge

PerrymanPerryman(Gas, Oil (Gas, Oil CTsCTs))360 MW360 MW

Crane (Coal Crane (Coal StmStm and Oil CT)and Oil CT)399 MW399 MW

Notch CliffNotch Cliff(Gas (Gas CTsCTs) 128 MW) 128 MW

PhiladelphiaPhiladelphiaRoad (Oil Road (Oil CTsCTs) 64 MW) 64 MW

Riverside (Gas Riverside (Gas StmStm and Gas, Oil and Gas, Oil CTsCTs) 249 MW) 249 MW

Wagner (Coal, Gas, Oil Wagner (Coal, Gas, Oil StmStm and Oil CT) 1015 MWand Oil CT) 1015 MWBrandon Shores (Coal) 1286 MWBrandon Shores (Coal) 1286 MW

WestportWestport(Gas CT)(Gas CT)121 MW121 MW

KEN230

230

230

115

115

115

115

115

11511

5

115

115

115

115

115

115 115

115

115

115

115

115

Bethlehem Steel

Edgewood

brook

Harford

Mays Chapel

Northeast

heart Cup

Taunton Energy Center

1001 MW

Generation Assets

100

100

MMWh60.8Total

MMWh2.7Other

MMWh31.1Nuclear

MMWh8.4Gas

MMWh18.6Coal

CEG 2006E

Fuel Mix

Coal, 23%

Gas, 31%

Nuclear, 32%

Other, 14%

MW11,856Total

MW1,608Other

MW3,794Nuclear

MW3,722Gas

MW2,732Coal

CEG 2005

Coal, 23%

Gas, 31%

Nuclear, 33%

Other, 13%

MW11,941Total

MW1,610Other

MW3,877Nuclear

MW3,722Gas

MW2,732Coal

CEG 2006E

Coal, 30%

Gas, 14%

Nuclear, 52%

Other, 4%

MMWh60.2Total

MMWh2.5Other

MMWh31.4Nuclear

MMWh8.2Gas

MMWh18.1Coal

CEG 2005

Coal, 31%

Gas, 14%

Nuclear, 51%

Other, 4%

Installed Capacity

Generation

101

101

Nuclear Fuel

$(8)

133

$(16)$(2)Change

1211282005 Capital Plan

$137$1302006 Capital Plan $141

20072006E2005($ in millions)

102

102

Portfolio Management – Limiting Variability

Percent Hedged

0.070.020.01Fuel down $0.10/MMBtu, Power unch.

($0.05)($0.05)($0.01)Power down $1/MWh, Fuel unchanged

[1] Does not sum due to roundingNote: As of 12/31/2005; Percent hedged includes Mid-Atlantic Fleet, Plants with PPA’s, Power Wholesale and Retail

Competitive Supply.

61%82%99%Fuel

$0.02

Sensitivity to Price Changes

($0.03)($0.01)Power down $1/MWh, Fuel down $0.10/MMBtu [1]

82%95%Power 79%

200820072006

103

103

2005 vs. 2004 Mid-Atlantic Fleet Variable Costs

Note: Does not add due to rounding

$/MWhTWh$

(Millions)$/MWhTWh$

(Millions)

-

$14.61

0.69

0.81

50.02

16.81

$4.91

$39.77

33.7

-

-

1.6

18.2

13.9

33.4

33.3

$492

23

15

80

306

$68

$1,328

2004 Plan

$18.1534.7$630Total Expenses

3.07-55Emissions

69.502.4167Oil/Gas/Other Gen

18.0717.8322Coal

$4.5614.5$66Nuclear

Expenses:

0.59-20Other

$42.2834.6$1,463Total Revenue

34.0Memo: Actual TWh produced

2005 Plan

104

104

2006E Mid-Atlantic Fleet Variable Costs (1H)

Note: Numbers do not add due to rounding

$/MWhTWh$

(Millions)$/MWhTWh$

(Millions)

$17.98

0.76

2.82

60.73

17.93

$4.55

$41.68

17.3

-

-

1.3

9.1

6.9

17.3

16.2

$310

13

26

78

162

$32

$720

1H 2005 Plan


4.89-44Emissions


24.369.1221Coal

$4.556.8$31Nuclear

Expenses:

0.16-3Other

$41.6916.8$702Total Revenue

Memo: Actual TWh Produced

1H 2006 Plan

105

105

2006E Mid-Atlantic Fleet Variable Costs (2H)

Note: Numbers do not add due to rounding

$/MWhTWh$

(Millions)$/MWhTWh$

(Millions)

$18.34

0.42

3.33

79.49

18.22

$4.56

$42.87

17.4

-

-

1.1

8.7

7.6

17.4

17.8

$320

7

29

89

159

$34

$747

2H 2005 Plan


4.90-44Emissions


25.548.9219Coal

4.497.6$34Nuclear

Expenses:

0.16-3Other

$55.1717.6$968Total Revenue

Memo: Actual TWh Produced

2H 2006 Plan

106

106

Wholesale Competitive Supply

158 186 201

37845287

171 197

415372

$0

$200

$400

$600

$800

$1,000

2002 2003 2004 2005 2006E

Mil

lion

s

Current Gross Margin Future Gross Margin

107

107

Synfuel EBIT to Net Income2004 TOTAL 2005 TOTAL 2006 TOTAL 2007 TOTAL

Pace Synfuel Actual Actual Estimate Estimate

Net Operating Loss (23.6)$ (32.2)$ (36.5)$ (36.9)$ Deferred Contingent Fee 10.0 3.7 4.1 4.2

EBIT (13.7) (28.5) (32.4) (32.7) Tax benefit of pre-tax loss 4.8 10.0 11.3 11.5 Tax credits 33.4 44.6 53.5 54.2

Net Income 24.5$ 26.1$ 32.5$ 32.9$

Production (tons in millions) 1.2 1.5 1.8 1.8

2004 TOTAL 2005 TOTAL 2006 TOTAL 2007 TOTALSouth Carolina Synfuels Actual Actual Estimate Estimate

Gross Margin (23.5)$ (19.4)$ (24.2)$ (24.2)$ Operating Expenses 4.1 9.7 29.0 29.2 Amortization of Purchase Price 15.1 25.3 10.5 10.5

EBIT (42.7) (54.4) (63.7) (63.9) Imputed Interest 1.1 2.4 0.9 0.3

EBT (43.8) (56.9) (64.6) (64.2) Tax benefit of pre-tax loss 17.0 22.1 25.1 25.0 Tax credits 53.9 69.0 85.9 87.2 Net Income 27.1$ 34.2$ 46.4$ 48.0$

Production (tons in millions) 1.8 2.2 3.0 3.0

Total Synfuel Net Income 51.7$ 60.3$ 78.9$ 80.8$

Total Synfuel EPS 0.30$ 0.34$ 0.44$ 0.44$

Assumed Phase Out (0.13) (0.10)

Total Adjusted Synfuel EPS 0.30$ 0.34$ 0.31$ 0.34$

108

108

Competitive Transition Charge (CTC)

($66)$39$105Merchant Portion

515BGE portion

[1] Collection of CTC ends June 30, 2006

($76)$44$120Expected CTC Revenue (millions)

$3.71$4.20Total

$5.50$5.48Industrial

$5.90$4.90Commercial

$2.64$3.01Residential

Blended CTC Rates ($/MWh)

Change2006E [1]2005

109

109

Productivity

$ 40.2 Total Productivity$ 33.2 Total Cost Productivity

$ 7.14.2 Other

$ 2.9 Information TechnologyOther:

$ 8.2 0.5 Other 4.7 Major Maintenance

$ 3.0Outage ChangesCalvert Cliffs:

$ 17.9 7.5Contractors, Material and Other

$ 10.4 Outage Changes Nine Mile Point:Costs

$ 7.0 Total Gross Margin Productivity$ 0.5 Other Gross Margin improvements$ 0.7

$ 0.7 Outage DaysGinna:

$ 5.8 0.3 Additional MWs from LP rotor replacement

$ 5.5 Outage DaysNine Mile Point:

2006Gross Margin$ in millions

E

110

110

Merchant Margin Statistics

[2] NewEnergy normalized for TX rate issue

[4] Includes Mid-Atlantic Fleet, Plants with PPA’s and QFs

[3] Operating expenses include depreciation and amortization

[1] Includes allocation of corporate overhead

79%Approx. Generation Group O&M as a % of Gross Margin [3]

Generation Fleet [1], [4]

$36Expenses for gas-fired plants in MISO and Texas (millions)

48%Approximate Operating Expenses as a % of Gross Margin [3]

Wholesale Competitive Supply [1]

70%Approximate Operating Expenses as a % of Gross Margin [3]

NewEnergy [1], [2]

2006E

111

111

2006E Fossil PPA Plants

May 20062010Contracted Through

10100Starts

0.0064.3TWh

Assumptions:

2.5168.2Gross Margin

0.012.2Replacement Power

3.02.25($ / MWh)

0.0189.8VOM Revenue

8,50010,000($ / start)

0.0851.0Start Revenue

0.512.1($ millions / month)

2.4145.2Capacity PaymentsUniversity ParkHigh Desert

112

112

2006E Nuclear PPA Plants

[1] After termination, revenue sharing agreement in place with former owners through 2021

83MW uprateplanned for 2006

Other

June, 2014Unit 1: August, 2009

Unit 2: November 2011[1]Contracted Through:

4.112.6 TWh

Long-term unit contingent agreement to sell 90% of output and capacity to RG&E

at average price of $44/MWh

90% of output sold to former owners at average of nearly

$35/MWh

Contract Terms

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

Ownership

498 MWUnit 1: 620 MWUnit 2: 941 MW

Unit Capacity

GinnaNine Mile Point

113

113

BGE Gross Margin

See Appendix

$1,274$1,253Total Gross Margin

321285Gas Margin

$953$968Electric Gross Margin

$2,130$1,757Total Cost of Goods Sold

813688Gas Purchased for Resale

$1,317$1,069Electricity Purchased for Resale

$3,404$3,010Total Regulated Revenue

1,134973Gas Revenue

$2,270$2,037Electric Revenue

2006E2005($ in millions)

114

114

BGE 2006 Electric T&D Overview

31.41,206,331Total

$23.390.878460-599 KW

$32.670.14,2600-59 KW

$11.331.9126600+ KW

Industrial

$12.886.0539600+ KW

$24.045.88,77660-599 KW

$32.593.4105,5290-59 KW

Commercial

$34.9213.41,086,316Residential

2006 T&D / MWh Rates

2006 MWh(millions)CustomersCustomer Class

115

115

BGE Electric T&D Quarterly Profile

Excludes Special Items

See Appendix

485,60532,822,2782006 E

515,974511,15833,312,068Total

Weather 3.1% colder than normal118,16774,8427,843,556Q4

Weather 18% warmer than normal149,984423,5169,565,100Q3

Weather cooler than normal108,404(52,879)7,496,858Q2

Weather 3.7% colder than normal139,41865,6798,406,554Q1

Includes increased reliability initiatives2005

Comments/DriversEBITDA

(millions)MWhs vs. NormalMWhsPeriod

116

116

BGE POLR Overview

$9.5$1.50$4.006.3193%Residential

Note: MWh projections are weather normalized

$22.612.85Total

0.42.252.550.16600+ KWhourly

0.82.006.000.4253%60 – 599 KW

0.22.005.500.0885%0 – 59 KW

Industrial

600+ KW

6.02.006.003.0253%60 – 599 KW

5.72.005.502.8685%0 – 59 KW

Commercial

2006E POLR

Return

POLR Return/

MWhPOLR

Adder/MWh

2006E POLR (MWh)

RetentionRate

(MWh and $ in millions)

Customer Class

117

117

BGE POLR Retention Assumptions

Note: MWh projections are weather normalized

$16.98.31Total

0.72.252.550.32Hourly

0.23.006.500.068%600+ KW

1.12.006.000.5365%60 – 599 KW

0.22.005.500.1098%0 – 59 KW

Industrial

0.63.006.500.188%600+ KW

7.72.006.003.8665%60 – 599 KW

$6.5$2.00$5.503.2698%0 – 59 KW

Commercial

2005 POLR

Return

POLR Return/

MWhPOLR

Adder/MWh2005 POLR

(MWh)Retention

Rate

(MWh and $ in millions)

Customer Class

118

118

BGE Gas Delivery Quarterly Profile

[1] EBITDA excluding off-system sales and special items

$9$128641,0892006E

$11$109Total 2005

433634,051Q4

03630,714Q3

114629,944Q2

$6$58628,802Q1

2005

Gains from Cost Sharing

(millions)EBITDA [1]

(millions)CustomersPeriod

See Appendix

119

119

Capitalization Effects

(millions except for per share) 06E 05 Change Merchant BGE ONR

InterestAvg Debt Balance 4,805$ 4,974$ (169)$

Interest Expense 304$ 307$ (3)$

Avg Cash Pool Balance 759$ 681$ 78$

Interest Income - Cash Pool (35)$ (23)$ (13)$

Interest Income - Other (1)(5)$ (17)$ 12$

Capitalized Interest (2)(13)$ (8)$ (5)$

Total Net Interest Expense 251$ 260$ (9)$

Impact on EPS 0.03$ 0.03$ (0.02)$ 0.02$

DilutionShares Outstanding for EPS Purposes 182.1 179.9

Dilutive Impact of Employee Stock Options (0.05)$

(0.02)$

(1) Included in Other Income in Income Statement

(2) Capitalized interest on construction projects underway

120

(229)Dividends

97Equity Issuances – Benefit Plans

8667511780Asset Dispositions & Contract Restructuring1

(535)124(114)(545)Working Capital & Other2

16Pension Adjustment (pre-tax)

665(1,076)

50(42)

244(302)

371(732)

Depreciation & AmortizationCapital Expenditures & Investments

$429

$56120820317Free Cash Flow

$(411)$8$(58)$(361)Net CapEx

625$1$181$443Net Income Before Special Items

TotalOther

Non-RegUtilityMerchant($ in millions)

2005 Consolidated Cash Flow

Net Cash Flow before Debt Issuances/(Payments)

1) $866m includes $562m from contract restructurings, $72m from the sale of Panama and $218 from the sale of Oleander

2) Working capital use primarily driven by higher AR & fuel stocks, both associated with rising commodity prices, business growth and the increased value of emissions credits

See Appendix

121

Non-GAAP Reconciliations

122

122

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

Non-GAAP Measure in Presentation Most Comparable GAAP Measure Reconciliation

ADJUSTED EPS Reported GAAP EPSYTD 2005 Actual 6 , 7, 17, 51, 55, 56, 57, 61, 64, 65, 70, 75 123YTD 2004 Actual 6 , 7, 17, 51 123YTD 2003 Actual 7, 17 124YTD 2002 Actual 7, 17 124Q405 Actual 49, 50 125Q404 Actual 49, 50 125Q105 Actual 93 126EPS Guidance 6 , 17, 51, 55, 56, 57, 61, 64, 65, 70, 75, 91 123Q405 Guidance 49, 50 125Q106 Guidance 93 126

Merchant Gross Margin 21, 35, 58, 79, 80 Income from Operations / Net Income 127Merchant Below Gross Margin 80, 81 127Merchant Projected Gross Margin 35, 79, 80 127Merchant Projected Below Gross Margin 58, 80 127

Wholesale Competitive Supply Gross Margin 21, 35, 58 Income from Operations 128

NewEnergy Gross Margin 40, 62 Income from Operations 130NewEnergy EBIT, Projected EBIT 62 130NewEnergy Projected Gross Margin 62 130

BGE Gross Margin 77, 113 Income from Operations / Net Income 129BGE EBIT 77 129BGE EBITDA 115, 118 129BGE Below Gross Margin 77 129BGE Projected Gross Margin 77 129

Debt to Total Capital 15, 87 Debt Divided by Total Capitalization 132Projected Debt to Total Capital 15, 87 132

Net Cash Flow before Debt Issuances (Payments) 120 Operating, Investing and Financing Cash Flow 131Free Cash Flow 120 131Projected Cash Flow 85 131

123

123

Adjusted EPS YTD 2005 and 2004We exclude special items and certain economic, non-qualifying fuel adjustment clause and gas transportation 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 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 these non-GAAP measures involve judgment by management (in particular, judgments as to what is or is not classified as a special item). We also use these measures to evaluate performance and for compensation purposes.

RECONCILIATION:Merchant Regulated Regulated OtherEnergy Electric Gas BGE Nonreg. Total

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

2005 ACTUAL RESULTS:

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

Income from Discontinued Operations 0.02 - - - 0.11 0.13 GAAP MEASURES

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

2.39 0.83 0.15 0.98 0.01 3.38

Special Items and Non-qualifying Hedges Included in Operations:

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

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

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

Total Special Items and Non-qualifying Hedges (0.21) (0.02) (0.01) (0.03) - (0.24)

Adjusted EPS 2.60$ 0.85$ 0.16$ 1.01$ 0.01$ 3.62$ NON-GAAP MEASURE

2004 ACTUAL RESULTS:Reported GAAP EPS 2.27$ 0.75$ 0.13$ 0.88$ (0.03)$ 3.12$

(Loss) Income from Discontinued Operations (0.21) - 0.05 (0.16) GAAP MEASURESEPS Before Discontinued Operations 2.48 0.75 0.13 0.88 (0.08) 3.28

Special Items Included in Operations:

Recognition of Prior Year Synthetic Fuel Tax Credits 0.21 - - - - 0.21

Workforce Reduction Costs (0.03) - - - - (0.03)

Impairment Losses and Other Costs - - - - (0.01) (0.01)

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

Total Special Items 0.18 - - - (0.02) 0.16 Adjusted EPS 2.30$ 0.75$ 0.13$ 0.88$ (0.06)$ 3.12$ NON-GAAP MEASURE

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

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

124

124

Adjusted EPS YTD 2003 and 2002We exclude special items and certain economic, non-qualifying fuel adjustment clause and gas transportation 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 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 these non-GAAP measures involve judgment by management (in particular, judgments as to what is or is not classified as a special item). We also use these measures to evaluate performance and for compensation purposes.

RECONCILIATION:

2003 ACTUAL RESULTS:Reported GAAP EPS 1.66$ Income from Discontinued Operations 0.09 GAAP MEASURESCumulative Effects of Changes in Accounting Principles (1.19)

2.76 Special Items and Non-qualifying Hedges Included in Operations:

Non-qualifying Hedges (0.17) Net Gain on Sales of Investments and Other Assets 0.10 Workforce Reduction Costs (0.01) Total Special Items and Non-qualifying Hedges (0.08)

Adjusted EPS 2.84$ NON-GAAP MEASURE

2002 ACTUAL RESULTS:Reported GAAP EPS 3.20$ Income from Discontinued Operations 0.06 GAAP MEASURES

3.14

Special Items Included in Operations:

Net Gain on Sales of Investments and Other Assets 1.02 Impairment Losses and Other Costs (0.11) Workforce Reduction Costs (0.23) Total Special Items 0.68

Adjusted EPS 2.46$ NON-GAAP MEASURE



125

125

Adjusted EPS 4Q05 and 4Q04We exclude special items and certain economic, non-qualifying fuel adjustment clause and gas transportation 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 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 these non-GAAP measures involve judgment by management (in particular, judgments as to what is or is not classified as a special item). We also use these measures to evaluate performance and for compensation purposes.


A B C D = (B+C) E F =(A+D+E) 4Q05 ACTUAL RESULTS:Reported GAAP EPS 0.78$ 0.17$ 0.05$ 0.22$ 0.09$ 1.09$ Income from Discontinued Operations - - - - 0.09 0.09 GAAP MEASURESCumulative Effects of Changes in Accounting Principles (0.04) - - - - (0.04)

0.82 0.17 0.05 0.22 - 1.04 Special Items and Non-qualifying Hedges Included in Operations:

Non-qualifying Hedges 0.06 - - - - 0.06 Merger related transaction costs (0.06) (0.02) (0.01) (0.03) - (0.09) Total Special Items and Non-qualifying Hedges - (0.02) (0.01) (0.03) - (0.03)

Adjusted EPS 0.82$ 0.19$ 0.06$ 0.25$ -$ 1.07$ NON-GAAP MEASURE

4Q04 ACTUAL RESULTS:Reported GAAP EPS 0.58$ 0.13$ 0.04$ 0.17$ 0.01$ 0.76$ Income from Discontinued Operations 0.02 - - - 0.03 0.05 GAAP MEASURESEPS Before Discontinued Operations 0.56 0.13 0.04 0.17 (0.02) 0.71 Special Items and Non-qualifyting Hedges Included in Operations:

Non-qualifying Hedges 0.03 - - - - 0.03 Workforce Reduction Costs (0.03) - - - - (0.03) Total Special Items and Non-qualifying Hedges - - - - - -

Adjusted EPS 0.56$ 0.13$ 0.04$ 0.17$ (0.02)$ 0.71$ NON-GAAP MEASURE

EARNINGS GUIDANCE (4Q05, 1Q06):Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact ofspecial items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.


126

126

Adjusted EPS 1Q05We exclude special items and certain economic, non-qualifying fuel adjustment clause and gas transportation 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 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 these non-GAAP measures involve judgment by management (in particular, judgments as to what is or is not classified as a special item). We also use these measures to evaluate performance and for compensation purposes.


A B C D = (B+C) E F =(A+D+E) 1Q05 ACTUAL RESULTS:Reported GAAP EPS 0.28$ 0.24$ 0.16$ 0.40$ -$ 0.68$ Income from Discontinued Operations - - - - 0.01 0.01 GAAP MEASURESEPS Before Discontinued Operations 0.28 0.24 0.16 0.40 (0.01) 0.67 Special Items and Non-qualifyting Hedges Included in Operations:

Non-qualifying Hedges (0.04) - - - - (0.04) Adjusted EPS 0.32$ 0.24$ 0.16$ 0.40$ (0.01)$ 0.71$ NON-GAAP MEASURE

EARNINGS GUIDANCE (4Q05, 1Q06):Constellation Energy is unable to reconcile its earnings guidance excluding special items to GAAP earnings per share because we do not predict the future impact ofspecial items such as the cumulative effect of changes in accounting principles and the disposition of assets. See above reconciliation for actual Special Items.

127

127

2005 Merchant Gross Margin and Below Gross MarginWe utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Mid-Atlantic Fleet, Plants with PPAs, Wholesale Competitive Supply, NewEnergy, and QFs/Other). We believe this non-GAAP measure helps investors to better understand the changes in the level of our Merchant Energy operating results for these categories from period to period.

RECONCILIATION:GAAP Adjustments Merchant

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

($ millions)Mid-Atlantic Fleet 2,283.9$ 1,436.5$ 847.4$ (12)$ a, b, c 836$ Plants with PPAs 829.6 79.6 750.0 3 a 753 Wholesale Competitive Supply 4,672.3 4,124.6 547.7 50 a , d 598 **NewEnergy 6,942.3 6,668.2 274.1 274 QFs / Other 58.0 - 58.0 (40) e 17

Total Merchant 14,786.1$ 12,308.9$ 2,477.2$ 1$ 2,478$

Adjustments Merchant Below Arriving At Merchant Gross Margin

Total Merchant: GAAP Below Gross Margin (Non-GAAP)Revenues less fuel and purchased energy expenses 2,477.2$ 2,478$ Operations and maintenance expenses (1,364.3) 44 f, g (1,320) Merger related transaction costs (11.2) 11 h - Workforce reduction costs (4.4) 4 h - Depreciation and amortization (269.6) (24) g (294) Taxes other than income taxes (112.2) 112 i - Accretion of asset retirement obligations (62.1) 62 i -

Income From Operations 653.4 864 Other income / (expense) 36.6 (173) b, i, j, l (136)

EBIT N/A 728 Fixed charges (177.9) 14 j (164)

Income Before Income Taxes 512.1 564 Income tax expense (81.9) (14) h, k, l (96)

Income from Continuing Operations Before Cumulative Effects of Changes in Accounting Principles 430.2 468

Income from discontinued operations 3.0 (3) h - Cumulative effects of changes in accounting principles (7.4) 7 h -

Net Income 425.8$ 468$

Details of Adjustments Made in Arriving at Merchant Gross Margin:a Adjustment to remove ($12 million) from Mid-Atlantic Fleet and $3 million from Plants with PPA's of estimated gross margin created through active portfolio

management more appropriately categorized as a competitive supply activity.b Adjustment to remove $20 million of decommissioning revenues from non-GAAP gross margin measure and included in Other Income. The offsetting decommissioning expense

was recorded in accretion of asset retirement obligations.c Adjustment to remove ($20 million) of other indirect costs have been removed from non-GAAP gross margin as they are more appropriately categorized as operating expenses.d Adjustment to remove $42 million loss related to economic, non-qualifying hedges of fuel adjustment clauses and gas transport contractse Adjustment to reflect $40 million of direct costs in Other for purposes of non-GAAP gross margin measure.

Details of Adjustments Made in Arriving at Merchant Below Gross Margin:f Adjustment detailed in "c" and "e" above are offset by adjustments made to O&M costs. g Adjustment to reclassify certain allocated costs totaling $24 million from O&M to Depreciation and Amortizationh Adjustment to remove Special Items and related taxes, which are not included in determining Merchant Below Gross Margin.i Adjustment to reflect management's view of these items as Other Income / Expense.j 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 tax benefit ($16 million) related to losses on economic, non-qualifying hedges of fuel adjustment clauses and gas transport contractsl Adjustment to move taxes $4 million related to nuclear decommissioning to Other Income / Expense.

** Includes $19 million of negative gross margin associated with operating losses at our South Carolina synfuel facility.

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

Year Ended December 31, 2005

128

128

2004 and 2003 Wholesale Competitive Supply Gross MarginWe utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Wholesale Competitive Supply operation. We believe this non-GAAP measure helps investors to better understand the changes in the level of our operating results from period to period.

RECONCILIATION:GAAP Adjustments Merchant

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

($ millions)Wholesale Competitive Supply 3,353.8$ 3,113.4$ 240.4$ 124$ a 364$ *

a Adjustment to remove $121 million from Mid-Atlantic Fleet and $3 million from Plants with PPA's of estimated gross margin created through active portfolio management more appropriately categorized as a competitive supply activity.

* Includes $23 million of negative gross margin associated with operating losses at our South Carolina synfuel facility.

GAAP Adjustments MerchantGAAP Fuel & Purchased In Arriving Gross Margin

Revenue & Expense Categories Revenues Energy Expenses Difference At Gross Margin Notes (Non-GAAP)($ millions)

Wholesale Competitive Supply 2,703.9$ 2,553.1$ 150.8$ 97$ a 248$ **

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

** Includes $10 million of negative gross margin associated with operating losses at our South Carolina synfuel facility and $13 million associated with losses on non-qualifying economic hedges.



129

129

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

RECONCILIATION:

Utility:GAAP Electric

Segment ResultsGAAP Gas Segment

ResultsTotal Utility

Results Adjustments Notes (Non-GAAP)Revenue

Total Electric Revenues 2,036.5$ -$ 2,036.5$ Total Gas Revenues - 972.8 972.8 Total Regulated Revenues 2,036.5 972.8 3,009.3

Operating ExpensesPurchased Power Costs

Electricity Purchased for Resale (1,068.9) - (1,068.9) Gas Purchased for Resale - (687.5) (687.5) Total Purchased Power Costs (1,068.9) (687.5) (1,756.4)

Gross Margin 967.6 285.3 1,252.9 1,253$ Operations and maintenance expenses (318.4) (131.8) (450.2) (5) a (456) Merger related transaction costs (4.0) (1.4) (5.4) 5 b - Depreciation and amortization (185.8) (46.6) (232.4) (232) Taxes other than income taxes (135.3) (33.1) (168.4) 168 c -

Income From Operations 324.1 72.4 396.5 565 Other income 6.8 1.9 8.7 (169) a, c, d (161)

EBIT N/A N/A N/A 404 Interest expense (69.5) (24.0) (93.5) 4 d (89)

Income Before Income Taxes 261.4 50.3 311.7 315 Income tax expense (101.2) (21.2) (122.4) 1 b (120)

Net Income 160.2 29.1 189.3 195 Preference Stock Dividends (10.8) (2.4) (13.2) (13) Earnings Applicable to Common Stock 149.4$ 26.7$ 176.1$ 182$

Details of Adjustments:a Adjustment to reclassify certain BGE costs required by regulation to be recorded in Other Expense to Operating Expense. b Adjustment to remove the merger related transaction costs and related taxes that management views as a special item.c Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. d Adjustment to move Interest Income recorded in Other Expense to Fixed Charges (to show a fixed charge amount net of interest income).

Calculation of EBITDA:Gross margin 968$ 285$ Operations and maintenance expenses (318) (132) Taxes other than income taxes (135) (33)

EBITDA 2005 515$ 120$

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.


130

130

NewEnergy EBITWe utilize the non-GAAP financial measure of EBIT to highlight the primary driver of earnings at NewEnergy. We believe this non-GAAP measure helps investors to better understand the changes in the level of NewEnergy operating results from period to period.

RECONCILIATION:

NewEnergy: GAAP Adjustments Notes (Non-GAAP)Revenues 6,942.3$ 6,942$ Purchased fuel and energy expenses (6,668.2) (6,668) Revenues less purchased fuel and energy expenses 274.1 274 Operations and maintenance expenses (176.0) 17 a (159) Depreciation and amortization (4.0) (4) Taxes other than income taxes (38.8) (39)

Income From Operations 55.3$ 72

Other Income 1.3 1 Controllable EBIT N/A 73$

Details of Adjustments Made in Arriving at NewEnergy EBIT:a Adjustment to remove corporate allocated O&M expenses.

PROJECTED EBIT:Constellation Energy is unable to reconcile its projected EBIT 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.


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Cash FlowsThe following is a reconciliation of the non-GAAP financial measures of Cash Flow for Debt Reduction and Free Cash Flow for the year ended December 31, 2005. We utilize this non-GAAP measures because we believe they are helpful in understanding our ability to reduce debt by existing cash.

RECONCILIATION:

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

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

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

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

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

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

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

Free Cash Flow 561$ NON-GAAP MEASURE

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

2005($ millions)

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132

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

RECONCILIATION:

Total long-term debt (gross of current portion) 4,610.9$ 4,610.9$ 5,046.4$ 5,046.4$ 5,134.9$ 5,134.9$ 4,799.8$ 4,799.8$ 3,874.4$ 3,874.4$

Fair value increase in fixed to floating rate swap included in long-term debt 0.9 (13.3) - -

6.20% deferrable interest subordinated debentures due

October 15, 2043 to BGE wholly owned BGE Capital Trust II

relating to trust originated preferred securities 257.7 257.7 257.7 257.7 257.7 257.7 250.0 250.0 250.0 250.0 50% Equity credit to trust preferred securities - (125.0) - (125.0) - (125.0) - (125.0) - (125.0) Short-term borrowings - - - - 9.6 9.6 10.5 10.5 975.0 975.0 Unamortized discount and premium (8.0) - (10.5) - (10.2) - (9.7) - (5.2) - Subtotal 4,860.6 4,744.5 5,293.6 5,165.8 5,392.0 5,277.2 5,050.6 4,935.3 5,094.2 4,974.4 LESS: Cash - 813.0 - 706.3 - 721.3 - 615.0 - 72.4 Total Debt 4,860.6 3,931.5 42.8% 5,293.6 4,459.5 46.5% 5,392.0 4,555.9 49.9% 5,050.6 4,320.3 5,094.2 4,902.0

BGE Preference Stock Not Subject To Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 190.0 190.0 190.0 190.0 190.0 Minority Interests - 22.4 - 90.9 - 113.4 - 105.3 - 101.8 Common shareholders' equity 4,915.5 4,915.5 4,726.9 4,726.9 4,140.5 4,140.5 3,862.3 3,862.3 3,843.6 3,843.6 Subtotal 5,105.5 5,127.9 4,916.9 5,007.8 4,330.5 4,443.9 4,052.3 4,157.6 4,033.6 4,135.4 50% Equity credit to trust preferred securities - 125.0 - 125.0 - 125.0 - 125.0 - 125.0

Total Equity 5,105.5 5,252.9 57.2% 4,916.9 5,132.8 53.5% 4,330.5 4,568.9 50.1% 4,052.3 4,282.6 4,033.6 4,260.4

Total Capitalization 9,966.1$ 9,184.4$ 100.0% 10,210.5$ 9,592.3$ 100.0% 9,722.5$ 9,124.8$ 100.0% 9,102.9$ 8,602.9$ 9,127.8$ 9,162.4$

Adjustment to include High Desert Lease on Balance Sheet at December 31, 2002 and December 31, 2001

Total Debt (above) 4,320.3 4,902.0 High Desert Financing 488.7 221.0 Adjusted Total Debt 4,809.0 52.9% 5,123.0 54.6%

Total Capitalization (above) 8,602.9 9,162.4 Adjustment for High Desert Financing (above) 488.7 221.0 Adjusted Total Capitalization 9,091.6$ 100.0% 9,383.4$ 100.0%

December 31, 2002GAAP Balances Non-GAAP Ratio


($ millions)


December 31, 2004 December 31, 2003GAAP Balances Non-GAAP Ratio GAAP Balances Non-GAAP Ratio

Economy & Finance

constellation energy Q4 2005 Earnings Presentation