constellation energy 2009 year-end earnings presentation february 22, 2010 1

Constellation Energy2009 Year-End Earnings Presentation

February 22, 2010

1

2

Forward Looking Statements Disclosure

Certain statements made in this presentation are forward-looking statements and may contain words such as “believes,” “anticipates,” “expects,” “intends,” “plans,” and other similar words. We also disclose non-historical information that represents management’s expectations, which are based on numerous assumptions. These statements are not guarantees of future performance and are subject to risks 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 and volatilities for energy and energy-related products including coal, natural gas, oil, electricity, nuclear fuel and emissions allowances and the impact of such changes on our liquidity requirements; the liquidity and competitiveness of wholesale and retail markets for energy commodities; the conditions of the capital markets, interest rates, foreign exchange rates, availability of credit facilities to support business requirements, liquidity and general economic conditions, as well as Constellation Energy’s and BGE’s ability to maintain their current credit ratings; the effectiveness of Constellation Energy’s and BGE’s risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments; losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets; the ability to successfully identify, finance and complete acquisitions and sales of businesses and assets, including generating facilities, and new nuclear generation development projects; the effect of weather and general economic and business conditions on energy supply, demand, and prices, and customers' and counterparties' ability to perform their obligations or make payments; the ability to attract and retain customers in our customer supply activities and to adequately forecast their energy usage; the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted in those markets; regulatory or legislative developments federally, in Maryland, or in other states that affect energy regulation, the price of energy, transmission or distribution rates and revenues, demand for energy, or that would increase costs, including costs related to safety or environmental compliance; the ability of our regulated and non-regulated businesses to comply with complex and/or changing market rules and regulations; the ability of BGE to recover all its costs associated with providing customers service; operational factors affecting the operations of our generating facilities and BGE’s transmission and distribution facilities, including 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 impact of industry consolidation; the impact of increased energy conservation and use of renewable energy; the actual outcome of uncertainties associated with assumptions and estimates requiring judgment when managing our business, applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors); changes in accounting principles or practices; and cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities. Given these uncertainties, you should not place undue reliance on these forward-looking statements. Please see our periodic reports filed with the SEC for more information on these factors. These forward-looking statements represent estimates and assumptions only as of the date of this presentation, and no duty is undertaken to update them to reflect new information, events or circumstances.

33

Use of Non-GAAP Financial Measures

Constellation Energy presents adjusted earnings per share (adjusted EPS) in addition to its reported earnings per share in accordance with generally accepted accounting principles (reported GAAP EPS). Adjusted EPS is a non-GAAP financial measure that differs from reported GAAP EPS because it excludes the cumulative effects of changes in accounting principles, discontinued operations, special items (which we define as significant items that are not related to our ongoing, underlying business or which distort comparability of results) included in operations, the impact of certain economic, non-qualifying hedges and synfuel earnings. The mark-to-market impact of these hedges has been significant to reported results, but economically neutral to the company in that offsetting gains or losses on underlying accrual positions will be recognized in the future. Synfuel earnings have been excluded due to the potential for oil-price volatility to result in a difficult-to-forecast phase-out of tax credits. Effective in 2009, we are no longer adjusting our reported GAAP EPS for either synfuel earnings, due to the expiration of the tax credit, or non-qualifying hedges, which were related to activities conducted by our recently divested operations.

We present adjusted EPS because we believe that it is appropriate for investors to consider results excluding these items in addition to our results in accordance with GAAP. We believe such a measure provides a picture of our results that is more comparable among periods since it excludes the impact of items such as impairment losses, workforce reduction costs or gains and losses on the sale of assets, which may recur occasionally, but tend to be irregular as to timing, thereby distorting comparisons between periods. However, investors should note that this non-GAAP measure involves judgment by management (in particular, judgment as to what is classified as a special item to be excluded from adjusted earnings). This non-GAAP measure is also used to evaluate management’s performance and for compensation purposes.

Constellation Energy also provides its earnings guidance in terms of adjusted EPS. Constellation Energy is unable to reconcile its guidance to GAAP earnings per share because we do not predict the future impact of special items due to the difficulty of doing so. In the past, the impact of special items has been material to our operating results computed in accordance with GAAP. Our earnings guidance excludes results of the UniStar joint venture and any impact from the operations and divestiture of our international commodities , Houston-based gas trading , international uranium marketing and west power trading operations, in addition to any other special items that may occur.

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

2009 Highlights

• Reported adjusted 2009 earnings of $3.36 per share, in-line with guidance range

• Completed all strategic initiatives outlined in year-end 2008 earnings call

– Closed EDF transaction and sale of non-core businesses

– Improved available liquidity and de-levered capital structure

– Achieved stable, investment grade credit ratings

• Strong operating performances by core businesses

– Set record capacity factors across the nuclear fleet

– Significantly completed key non-nuclear generation projects

– Realized strong Retail and Wholesale customer margins

– Established efficiency projects and developed a Smart Grid pilot program aimed at

reducing customer usage and bills

4See Appendix

Constellation successfully completed its announced initiatives ahead of schedule and at less cost, while also delivering solid financial results in 2009

Market Update

5

Constellation managed significant challenges in 2009 through active risk and portfolio management

NE NY PJM MISO-6%

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

Weather Normalized YoY Load Changes (%)

Jan-09 Apr-09 Jul-09 Oct-090

10

20

30

40

50

60

70

0

2

4

6

8

10

12

14

16

18

20

2011 PJM Flat Power, Dark Spreads w/ Emissions

7x24 Power Price Dark Spreads with Emissions

Po

wer

Pri

ce (

$/M

Wh

)

Dark S

pread

s ($/MW

h)

(1)

(2)

(1) Emissions include SO2, NOx and RGGI CO2(2) PJM Mid-Atlantic

Power prices and dark spreads deteriorated in 2009, but appeared to stabilize by year-end

Power demand in 2009 declined in most regions

Baltimore Gas & Electric (BGE) Overview

• Exceeded all key operational goals in 2009

• Increased BGE financial flexibility– Expanded existing credit facility from $400 million to $575 million

– Entered into a new, secured bond indenture

• Focused on reducing customer usage and bills– Continued capital investment in Smart Energy Savers Program

– Increased demand response capacity

– Full implementation of energy efficiency programs

• Key regulatory initiatives underway– Filed Smart Grid proposal with Maryland PSC

– Awarded $200 million stimulus grant for full deployment of Smart Grid program

– Completed all ring-fencing measures

6

BGE expects to earn reasonable returns on investments in reliability, load growth, energy efficiency and demand response

Generation Overview

• Strong operating performance with 90% reliability in 2009

• Completion of major environmental projects

– Brandon Shores Unit 1 scrubber on-time and within budget

– Environmental projects at Wagner and Crane coal facilities

– In-compliance with Maryland Healthy Air Act

• Substantially completed construction of a 740 MW combined cycle plant in Alabama

7

• Among the most productive fleets in the country

– 95.2% fleet capability factor in 2009 – highest among all U.S. nuclear fleets

• Set numerous plant and fleet records

– Calvert Cliffs Unit 2 set a world record for operating continuously for 692 days

– Completed refueling outages at Nine Mile Point and Ginna in approximately 20 days

• Closed nuclear joint venture with EDF

– Constellation will purchase approximately 90% of the uncommitted output from the JV

Non-Nuclear Generation Nuclear Generation

During 2009, Constellation’s existing generation fleet set plant records and completed a number of environmental and construction projects on-time and within budget

Customer Supply Overview

• Right-sized and reduced costs– Scaled business to size consistent with Constellation’s balance sheet

– Expect to serve over 30,000 customers and approximately 140 TWHs of load in 2010

– Reduced collateral needs

• Continued to secure high unit margins on new contracts signed in 2009– Average new business Retail margins were over $7.50/MWh

– Average new business Wholesale margins were approximately $3/MWh

• Expect strong unit margins going forward– Sustainable Retail Power margins of $5 - $7/MWh

– Sustainable Wholesale Power margins of $2 - $4/MWh

• Efforts to streamline the business and reduce operating costs continue

8

Building a scalable Customer Supply platform to support business activities in a disciplined, profitable and capital efficient manner

Investment Thesis• Positioned to invest in physical generation assets at attractive returns

– Significant excess cash balances and strong balance sheet

– Unique merchant business model

– Low commodity price environment and depressed asset values

• Leading retail and wholesale customer supply platforms

– Reduces cash and earnings volatility during periods of the commodity cycle

– Strengthen existing customer relationships by providing value-added products and services

• Opportunities for increased earnings profile at BGE

– Investment opportunities related to improving system reliability and efficiency

– Expect additional capital spending at BGE to increase regulated rate base

• Participating in the development of a new nuclear unit at Calvert Cliffs through the UniStar partnership

• Focus on further reducing the operating costs and improving the capital efficiency of the businesses

9

Going forward, Constellation is focused on an asset-backed investment strategy and the further reduction of operating costs in its businesses

Financial Overview

10

11

2009 Adjusted Earnings Per Share

($ per share) 2009 2008

Adjusted Earnings Per Share (1) $3.36 $3.57

Gain on Economic Non-Qualifying Hedges 0.00 (0.39)

Special Items 18.83 (10.52)

GAAP Earnings Per Share $22.19 ($7.34)

Adjusted Earnings Per Share Change

($ per share) 2009 2008 EPS %

BGE $0.80 $0.85 (0.05) (6%)

Merchant 2.58

2.69 (0.11) (4%)

Other Non-regulated

(0.02)

0.03 (0.05) N.M.

Adjusted Earnings Per Share (1)

$3.36

$3.57 ($0.21) (6%)(1) Excludes special items, and certain economic, non-qualifying hedges

See Appendix

12

Net Available Liquidity

(1) Excludes $0.5B of contractual facility capacity under commodity linked facility, under which the availability fluctuates with commodity price movements(2) Includes letters of credit posted under uncommitted facilities(3) Reserved cash comprised of net tax liability from EDF transaction ($0.7B) and cash to be used to fund voluntary debt retirement in Q1 2010 ($0.6B)(4) Includes $0.9 billion of net available liquidity at BGE as of year-end 2009. BGE was ring-fenced in February 2010

($ in billions) 12/31/2008 9/30/2009 (1) 12/31/2009 (1)

Credit facilities $6.6 $6.2 $4.1

Less: Letters of credit issued (2) (3.6) (2.0) (1.7)

Less: Cash drawn on credit facilities (0.9) - -

Undrawn facilities $2.1 $4.2 $2.4

Less: Commercial paper outstanding - (0.3) -

Net available facilities $2.1 $3.9 $2.4

Add: Cash 0.2 0.7 3.4

Less: Reserved Cash (3) - - (1.3)

Cash and Facility Liquidity $2.3 $4.6 $4.5

Add: EDF Put - 1.1 1.1

Total Net Available Liquidity $2.3 $5.7 $5.6 (4)

Downgrade collateral $1.8 $1.2 $1.1

13

Debt Maturity Profile

$0.0

$0.1

$0.2

$0.3

$0.4

$0.5

$0.6

$0.7

$0.8

$0.9

$1.0

2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065

($ in

bill

ions

)

Total CEG (excluding BGE) Total BGE Tender and Tax-exempt Purchase (1Q 2010)

- $550M CEG 4.55% Notes due 2015

- $700M CEG 7.60% Notes due 2032

(1) The total long-term debt includes the current portion of the long-term debtNote: Numbers may not add due to rounding.

$ in billions Proforma

CEG 12/31/08 12/31/09 3/31/1014% Senior Notes, due December 31, 2009 1.0$ -$ -$ 8% Series B Mandatorily Redeemable Preferred Stock 1.0 - - 6.125% Fixed-Rate Notes, due September 1, 2009 0.5 - - Zero Coupon Senior Notes, due June 19, 2023 0.3 - - 7.00% Fixed-Rate Notes, due April 1, 2012 0.7 0.7 0.2 4.55% Fixed-Rate Notes, due June 15, 2015 0.6 0.6 0.6 7.60% Fixed-Rate Notes, due April 1, 2032 0.7 0.7 0.7 8.625% Series A Jr. Sub Debentures, due June 15, 2063 0.5 0.5 0.5 Other 0.3 0.3 0.1

Total CEG excluding BGE 5.5$ 2.7$ 2.0$

BGE 2.3 2.2 2.2

TOTAL 7.7$ 4.9$ 4.2$

Constellation Energy Group Long-term Debt (1)

14

Balance Sheet Metrics

(1) Represents BGE’s investment in CEG cash pool at December 31, 2009. BGE exited the CEG cash pool in January 2010.(2) Based on our understanding of the S&P methodology and excluding special items.Note: Numbers are subject to change pending filling of 10K, and may not sum due to rounding

See Appendix

• Significantly de-levered Merchant balance sheet in 2009 and 2010

• Strong near-term investment grade credit metrics, with Merchant FFO/Debt ratios at 38%

Actual Forecast

2009 2010

($ in billions) BGE Merchant BGE Merchant

Cash Balance $0.3 $3.1 $0.1 $1.5

Balance Sheet Debt $2.2 $2.7 $2.1 $2.1

S&P Debt Adjustments (0.6) (0.2)

(0.7) (0.2)

S&P Imputed Debt 0.3 1.6 0.3 1.4

Total Adjusted Debt $1.9 $4.1 $1.8 $3.3

Balance Sheet Equity 2.1 6.8 2.2 6.9

S&P Equity Adjustments 0.1 0.8 0.1 0.8

Total Adjusted Equity $2.2 $7.6 $2.4 $7.8

Total Adjusted Capital $4.2 $11.7 $4.1 $11.0

Full Year FFO $0.7 $1.6 $0.5 $1.2

FFO/Debt Ratio (including Imputed Debt) 35% 40% 26% 38%

(2)

(2)

(2)

(1)

(2)

15

2010 & Beyond EPS Forecast

• 2010 and 2011 guidance range reflect current forward pricing curve and do not reflect the reinvestment of excess cash

• 2011 will benefit from the continued roll-off of existing lower margin contracts and increased earnings contribution from BGE

($ per share)

2010 2011 2012 2013 2014

Merchant and Other $1.95 – $2.15 $2.10 – $2.40 EPS Impact of $1.00 Power Price Exposure

$0.02 $0.03 $0.04

BGE $0.55 – $0.70 $0.75 – $0.90

EPS Impact of $1.00 Dark Spread Exposure (2)

Pre-Allocation EPS

(1) $2.45 – $2.85 $2.90 – $3.30 $ 0.04 $ 0.05 $ 0.05

JV PPA $0.55 - $0.60 $0.55 - $0.60 EPS Impact of 0.1x Heat Rate Exposure

$ 0.00 $ 0.01 $ 0.01

Total Adjusted EPS (1) $3.05 – $3.45 $3.45 – $3.85

(1) Data excludes Special Items, including the amortization of CENG basis differential, and UniStar earnings(2) Assumed MWhs exposed to Dark Spread movements equals the forecasted MWhs for coal-burning fleetSee Appendix

Additional Modeling

16

17

2009 Adjusted Earnings Recap

($ per share) Q1 2009 Q2 2009 Q3 2009 Q4 2009 FY 2009 FY 2008

Merchant $0.33 $1.03 $1.10 $0.12 $2.58 $2.69

BGE 0.41 0.06 0.14 0.18 0.80 0.85

Other Non-Regulated

0.00 (0.01) (0.01) 0.00 (0.02) 0.03

Total Adjusted EPS $0.74 $1.08 $1.23 $0.30 $3.36 $3.57

Adjusted Net Income $672.4M $639.4M

Avg. Diluted Shares 200.3M 179.1M

Note: Numbers may not add due to roundingSee Appendix

18

2009 Special ItemsItem

Gain/(Loss) per Share Description

Gain/(Loss) per Share Description

Q4 2009 FY 2009 CENG JV:

Gain on EDF Joint Venture $22.13 Primarily reflects the gain on the sale of the JV. Other special items related to the close of the JV included fees paid to advisors and fees associated with amendment/termination of certain credit facilities. Fourth quarter activity also reflects the recognition of tax benefits associated with certain costs incurred in prior periods, which became deductible for income tax purposes as a result of the closing of the EDF transaction. Also included is the non-cash expense associated with the basis difference between book value and fair value of the JV net assets

$22.25 Primarily reflects the gain on the sale of the JV. Other special items related to the close of the JV included fees paid to advisors and fees associated with amendment/termination of certain credit facilities. Also included is the non-cash expense associated with the basis difference between book value and fair value of the JV net assets

Transaction Related 0.08 (0.26)

Basis Difference (0.09) (0.09)

Sub-Total CENG JV: $22.12 $21.90

Divested Businesses - (1.86) Divestitures of our international commodities operations, Houston based trading operations, international uranium trading business, and west power trading operations

Impairment Costs (0.03) Primarily reflects the District Chilled Water

impairment (0.69) Reflects asset impairments primarily related to Shipping

JV, Nuclear Decommissioning Trust investments, divested business assets, and District Chilled Water.

BGE Customer Credit (0.34) Reflects the $112.4 million customer credit that was

accrued in November and expected to be applied to customer bills in Feb. 2010

(0.34) Reflects the $112.4 million customer credit that was accrued in November and expected to be applied to customer bills in Feb. 2010

Other Special Items (0.09) Includes UniStar equity earnings which are excluded

from adjusted earnings as the business remains in the development stage, workforce reduction costs for which quarter-to-date activity primarily reflects a change in our estimated annual effective tax rate at Dec. 31, 2009, requiring us to reduce the income tax benefit recognized in connection with charges recorded in the first half of the year, and losses related to the extinguishment of debt

(0.18) Includes UniStar equity earnings which are excluded from adjusted earnings as the business remains in the development stage, workforce reduction costs incurred in the first half of the year, and losses related to the extinguishment of debt

Total Special Items $21.66

$18.83

19

BGE – 2008 and 2009 Income Statement($ in millions except per share data) Change

2009 (1) 2008 (1) $ %

Electric Gross Margin $1,075 $989 $86 9%

Gas Gross Margin 326 330 (4) (1%)

Gross Margin $1,401 $1,318 $82 6%

O & M (563) (540) (23) (4%)

D & A (262) (228) (34) (15%)

Other Expenses (166) (166) 0 0%

EBIT $410 $385 $25 6%

Net Interest Expense (125) (121) (4) (3%)

Income Tax (113) (98) (16) (16%)

Preferred Dividends (13) (13) 0 0%

Net Income $158 $153 $6 4%

Adjusted EPS $0.80 $0.85 ($0.05) (6%)

Special Items (0.34) (0.64) 0.30 47%

GAAP EPS $0.46 $0.21 $0.25 118%(1) Adjusted earnings exclude special itemsNote: Numbers may not sum due to roundingSee Appendix

20

Merchant – 2008 and 2009 Income Statement

(1) Adjusted earnings exclude special itemsNote: Numbers may not sum due to roundingSee Appendix

Change

($ in millions except per share data) 2009 (1) 2008 (1) $ %

Generation $1,971 $1,891 $80 4%

Customer Supply 768 688 80 12%

Global Commodities 283 373 (89) (24%)

Gross Margin $3,023 $2,952 $71 2%

Equity Method Earnings 50 78 (27) (35%)

Operating & Maintenance (1,498) (1,685) 187 11%

Depreciation & Amortization (250) (285) 35 12%

Asset Retirement Obligation (62) (68) 6 9%

Other Revenue and Expenses (195) (27) (167) (610%)

Total Costs below Gross Margin ($1,955) ($1,988) $33 2%

EBIT $1,068 $965 $104 11%

Net Interest Expense (183) (174) (9) (5%)

Pre-Tax Income $885 $790 $95 12%

Income Tax (369) (308) (61) (20%)

Net Income $516 $482 $34 7%

Adjusted EPS $2.58 $2.69 ($0.11) (4%)

Special Items, Non-Qualifying Hedges and Synfuels $19.30 ($10.27) $29.57 NM

GAAP EPS $21.88 ($7.58) $29.46 NM

21

2009 Cash Flow

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

Segment Cash Flows

($ in millions) Merchant Regulated

Operating ActivitiesNet income (loss) $4,435 $105 ($37) $4,503Non-cash merger termination and strategic alternatives costs 128 - - 128Derivative contracts classified as financing activities under SFAS No. 149 1,138 - - 1,138Gain on sale of 49.99% membership interest in CENG (7,445) - - (7,445)Loss (gain) on divestitures 464 - 5 469Accrual of BGE residential customer credit - 112 - 112Impairment losses and other costs 98 - 27 125Other non-cash adjustments to net income (loss) 2,071 525 165 2,761Changes in working capital:

Derivative assets and liabilities, excluding collateral 419 - 6 425Net collateral and margin 1,520 3 - 1,523Other changes 803 21 (57) 767

Defined benefit obligations (1)- - - (287)

Other (44) 48 168 172Net cash provided by operating activities 3,587 814 277 4,391

Investing ActivitiesInvestments in property, plant and equipment (1,119) (372) (39) (1,530)Asset and business acquisitions, net of cash acquired - - (41) (41)Contributions to nuclear decommissioning trust funds (19) - - (19)Investments in joint ventures (110) - (92) (202)Proceeds from sale of 49.99% membership interest in CENG 3,529 - - 3,529Proceeds from sale of investments and other assets 50 - 38 88Contract and portfolio acquisitions (2,154) - - (2,154)

Decrease in restricted funds - (1) 1,004 1,003

Other - - - -

Net cash provided by investing activities 177 (373) 870 674

Cash flows from operating activities plus cash flows

from investing activities $3,764 $441 $1,147 $5,065

Financing Activities (1)

(2,660)Debt and credit facility costs (98)Proceeds from issuance of common stock 34Common stock dividends paid (228)BGE preference stock dividends paid (13)Proceeds from contract and portfolio acquisitions 2,263Derivative contracts classified as financing activities under SFAS No. 149 (1,138)Other 13

Net cash used in financing activities (1,827)Net increase in cash and cash equivalents $3,238

Holding Company and

Other Consolidated

Net repayment of debt

Capital Spending – BGE

22

($ in millions) 2009 2010E 2011E

Baltimore Gas & Electric

Electric / Gas Distribution $315 $414 $413

Electric Transmission 44 100 120

Smart Energy SaversSM Initiatives 76 102 178

Utility Total $436 $615 $711

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

23

Capital Spending – Merchant & Other

($ in millions) 2009 2010E 2011E

Merchant and Other

Major Environmental $ 318 $ 58 $ 25

Maintenance Capital Spending (1) 561 178 144

Growth (2) 279 309 153

Merchant and Other Total $1,158 $ 545 $ 322

Memo: Nuclear JV Capex 62 403 454

(1) 2009 Maintenance capital spending includes $359M of Nuclear capex prior to closure of JV(2) Growth Spending excludes equity contributions to the UniStar JV

Key drivers of capital expenditures:

– Environmental spending decline is driven by completion of scrubber projects in 2009 and Baltimore fly ash site purchase in 2010.

– Growth spending includes Hillabee Power plant in 2009, Criterion wind project in 2010, CEPS solar projects, and upstream gas production

Bank Facilities

24

$ in billions

Facility Capacity LC Postings Availability Expiration Date Capacity Type

Syndicated Revolver $ 2.3 $ 1.1 $ 1.3 July 2012 LC and Cash

Bi-lateral 0.6 0.5 $ 0.1 September 2014 LC

Bi-lateral 0.3 0.2 $ 0.1 June 2014 LC and Cash

Bi-lateral 0.3 - $ 0.3 December 2014 LC and Cash

Bi-lateral 0.2 - $ 0.2 September 2013 LC

Total Merchant Facilities $ 3.5 $ 1.7 $ 1.8

BGE Revolver 0.6 - 0.6 December 2011 LC and Cash

Consolidated Facilities 4.1 1.7 2.4

Memo: Contingent Capacity

Commodity-linked Facility $ 0.5 $ - August 2014 LC

Note: Numbers may not sum due to rounding

25

Projected 2010-2011 Net Available Liquidity

Note: BGE cash at December 2009 represents entity's investment in CEG’s cashpool. BGE exited cashpool in January 2010.

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

Dec-09 Mar-10 Jun-10 Sep-10 Dec-10 Mar-11 Jun-11 Sep-11 Dec-11

($ i

n b

illi

on

s)

BGE Cash BGE Facilities CEG Cash CEG Facilities

EDF Put Downgrade Collateral Merchant only NAL

2009 BGE Rate Base

26

Utility Plant $ 4,350 $ 1,399 $ 839 $ 6,588

Additions to Rate Base

110 107 6 223

Deductions from Rate Base

(2,212) (664) (366) (3,242)

Total Rate Base $ 2,248 $ 842 $ 479 $ 3,569

Regulated ROE 8.1%Book ROE 9.1%

Electric Transmission Total Utility($ in millions)

Electric Distribution

Gas Distribution

($ in millions) 2010E 2011E 2012E 2013E

Total Output (MM MWh’s) 32 32 32 33

Unhedged GM $1,506 $1,548 $1,546 $1,677

Total Expenses Direct O&M Other Generation Expense (1)

($624) (113)

($673) (109)

($682)(115)

($683) (112)

Unhedged EBITDA

Hedges

$769 $766 $750 $881

PPA/RSA Other

(76) (28)

(114) (5)

(71)10

(97)--

Total EBITDA

CEG Portion of EBITDA (2)

Hedge %

$665

$332

96%

$647

$323

72%

$688

$344

50%

$784

$392

33%

27

CENG Earnings Outlook

(1) Includes support costs, property taxes and other costs(2) Represents CEG’s 50% ownership stake in nuclear joint venture with EDF

Note: All forward curves as of 12/15/09. Numbers may not add due to rounding

28

Non-Nuclear Generation Earnings Outlook

($ in millions) 2010E 2011E 2012E 2013E

Plant Output (MM MWh’s)

Unhedged GM Coal & Other Non-Nuclear IPP/QF(1)

20

$65126

20

$618

33

20

$60132

20

$62721

Total Expenses Direct O&M Other Generation Expense (2)

(306) (90)

(316) (90)

(309) (85)

(323) (88)

Unhedged EBITDA $281 $245 $238 $237

Hedges 32 161 55 40

Total EBITDA

Total Generation Hedge % (3)

$312

100%

$406

73%

$293

42%

$276

29%

(1) Includes equity earnings component of IPP/QF not normally included in GM(2) Includes allocated headquarters costs, property taxes and other costs(3) Includes output from CENG PPA

Note: All forward curves as of 12/15/09. Numbers may not add due to rounding

29

Forward Market and Average Hedged Prices

(1) BGE zone is historically a 10%-20% premium to PJM WHUB pricing; Ginna/NMP zones are historically a 5%-15% premium to NY WHUB pricing(2) NY Capacity prices not disclosed in 2011 – 2013 as prices clear through a monthly auction(3) Includes current fixed priced portion of CENG PPA and existing NY PPAs/RSA(4) Coal prices ($/ton) do not include transportation costs of approximately $20 - $30 per ton

2010 2011 2012 2013

Market Curves (as of 12/15/2009)

NYMEX Gas ($/MMBtu) 5.8 6.6 6.8 6.9

NYMEX Coal ($/Ton) 53.9 66.9 75.3 80.3

PJM WHUB ($/MWh) (7 x 24) (1)

NY WHUB ($/MWh) (7 x 24) (1)

PJM Capacity Pricing ($/MWd)

NY Capacity Pricing ($/MWd) (2)

RGGI Emissions Expense ($/ton of CO2)

47.9

39.9

200.6

3.31

2.1

50.4

42.0

136.8

NA

2.1

51.7

42.0

123.8

NA

2.0

54.3

43.7

137.4

NA

2.0

Average Hedged Energy PricesPower – Non-Nuclear Plants ($/MWh) % Hedged Fossil

55.0100%

66.5 73%

65.1 42%

73.4 29%

Power – PJM Nuclear Plants ($/MWh) (3)

% Hedged PJM Nuclear

Power – NY Nuclear Plants ($/MWh) (3)

% Hedged NY Nuclear

51.6 99%

40.3 95%

54.4 64%

41.5 82%

54.5 32%

45.5 66%

-- 0%

43.5 59%

Average Hedged Fuel PricesCoal ($/ton) (4)

% Hedged 61.4

100%63.269%

63.8 22%

-- 0%

30

Generation Statistics(in MWh in thousands, unless otherwise stated) 2010E 2011E 2012E 2013E

Nuclear Plants (CEG Ownership Only)

Calvert 7,204 7,245 7,007 7,187

NMP 1 2,643 2,401 2,653 2,463

NMP 2 3,656 4,000 3,898 4,454

Ginna 2,483 2,253 2,341 2,485

Total Nuclear 15,986 15,899 15,899 16,589

Coal Plants

SW MAAC Coal Plants (Excluding QFs) 11,448 11,915 11,385 11,528

Other PJM Coal Plants 4,026 3,830 3,913 4,053

Total Coal 15,474 15,745 15,298 15,581

Gas / Oil Plants

PJM Gas/Oil Plants 290 261 307 374

Hillabee (Alabama) 1,318 1,348 1,549 1,760

West Valley (Utah) 308 262 270 281

Grand Prairie (Alberta, Canada) 143 122 142 143

Total Gas/Oil 2,059 1,993 2,268 2,558

Total QFs/Other (2) 2,327 2,341 2,294 2,020

Coal burn (MMtons) (1) 6.5 6.8 6.8 6.8

CO2 Emissions (MMtons) 17.5 18.3 17.8 17.3

(1) Includes Keystone and Conemaugh(2) Includes Safe Harbor; Criterion; Panther Creek; Colver; Ace Trona; Jasmin; Mammoth Lakes; Chinese Station; Fresno; Malacha; Poso; Rocklin; Sunnyside

31

Nuclear PPA Plants

Nine Mile Point Ginna

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

581 MW

CEG OwnershipUnit 1: 50.01% OwnedUnit 2: 41% Owned

50.01% Owned

Contract Terms

NMP2 PPA:• Long-term unit contingent agreements to sell

approximately 90% of CEG and EDF owned energy and capacity (82% of output) to former owners at average price of $35/MWh

NMP2 Revenue Sharing Agreement (1):• Strike price averages $40.75 for first year of

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

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

PPA:• Long-term unit contingent agreement

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

• Until Spring 2008, sell approx. 80% of energy and capacity to RG&E and thereafter approx. 90%.

Contracted Through: Unit 2 PPA: November 2011 June 2014

Other

105 MW uprate to be completed in 2012

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

Merchant Activities (Generation and Customer Supply)

32

Generation (TWhs)

(1) QFs in West and East regions(2) Existing PPAs on NY plants(3) Criterion Wind Project currently undergoing pre-construction activities, no MWh’s assumed in 2010(4) Wholesale excludes Mid-Marketing 6.0TWh and 14.6TWh for 2009 and 2010 respectively

Customer Supply (TWhs)

Estimated 2010

Total Open Position 58.2

Fixed Price Load 102.2

Generation/CSG Alignment 57%

Retail Wholesale (4)

2009 2010E 2009 2010E

Total Load 55.8 68.2 64.7 56.6

% Fixed Price 55% 67% 100% 100%

Fixed Price Position 30.7 45.6 64.7 56.6

PJM36%

ERCOT12%

NEPOOL25%

NYISO10%

Other17%

Retail Load Fixed Price Composition

PJM30%

ERCOT16%

NEPOOL7%

SOUTHEAST33%

Other14%

Wholesale Load Fixed Price Composition

PJM (3)

Owned: 24.2 Contracted: 8.0

WestOwned: 1.6 Contracted: 0.3

New YorkOwned: 8.8 Contracted: 2.8

Renewable Plants

Nuclear PlantsFossil Plants

MISOOwned: 0.0 Contracted: 0.6

NepoolOwned: 0.0Contracted: 1.9

SERCOwned: 1.3Contracted: 12.8

ERCOTOwned: 0.0Contracted: 3.1

Estimated 2010 Non-Nuclear Nuclear Total

Owned (Open Position) 18.2 10.5 28.7

Contracted 9.4 8.8 18.2

Entitlements 11.3 0.0 11.3

Total Open Position 38.9 19.3 58.2Owned (subject to PPA Offtake) (1),(2) 1.7 5.5 7.2

Total 40.6 24.8 65.4

33

Customer Supply

Backlog represents 78% and 43% of total Gross Margin we expect to realize in 2010 and 2011, respectively

Flow Volumes

Gro

ss M

arg

in$

mil

lio

ns

(1) Gross of Collateral Costs(2) Mark-to-market timing impact has been excluded from these numbers(3) Gas unit margins were normalized in the first and second quarters of 2009(4) Wholesale Power includes Mid-Marketing

Backlog as of 12/31/09

2005 2006 2007 2008 2009 2010E

Retail Power (TWh) 64 68 73 72 56 68

Wholesale Power (TWh)(4) 79 69 87 122 71 71

Total TWh 143 137 160 194 127 139

Retail Gas (Bcf) 300 354 410 407 350 341

2010E 2011E 2012E -

100.0

200.0

300.0

400.0

500.0

600.0

Retail Gas

Retail Power

Wholesale PowerV

olu

me (T

Wh

)

Retail Power

Ele

ctri

c G

M/M

Wh

(1)

4Q08 1Q09 2Q09 3Q09 4Q09

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

0

5

10

15

20

25

30

Electric Gross Margin/MWh Volume (TWh)

Vo

lum

e (Bcf)

Retail Gas

Gas

GM

/Dth

(2),(

3)

4Q08 1Q09 2Q09 3Q09 4Q09

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

0

20

40

60

80

100

120

Gas Gross Margin/Dth Volume (Bcf)

34

Economic Value at Risk (EVaR)

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

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

EVaR has declined 17% since the end of Q309, driven by the close of EDF JV transaction. Since last year, EVaR has declined 46% due to an overall decrease in unit VaR and the

successful completion of business transactions.

$50

$100

$150

$200

$250

30-S

ep

31-O

ct

30-N

ov

31-D

ec

31-J

an

28-F

eb

31-M

ar

30-A

pr

31-M

ay

30-J

un

31-J

ul

31-A

ug

30-S

ep

31-O

ct

30-N

ov

31-D

ec

$ in

Mill

ion

s

Economic Value at Risk (1)

Reduction due to sale of several Upstream gas assets and 12-15% decline In Unit VaR (2)

Reduction due to gas sales to hedge generation length and 10-12% decline in Unit VaR (2)

$179MM

$73MM

Reduction due to inclusion of only Proved Producing portion of Upstream Portfolio, consistent with our business plan Reduction due to

close of the EDF JV transaction

35

Wholesale Portfolio Credit Quality

Note: Based on internal credit ratings Subject to change pending filing of 2009 Form 10-K

During Q4’09, total wholesale exposure increased, largely due to the addition of exposure to Constellation Energy Nuclear Group. Non-investment grade counterparties now account for less than 13% of total exposure. Since last year, wholesale exposure has decreased 38%.

$ in

Mil

lio

ns

As of December 31, 2009

46%

44%

1% 5%

1%2%

1%

Domestic Coal International CoalFinancial FreightGas Municipalities/Cooperatives/UtilitiesPower

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

Dec-05

Dec-06

Dec-07

Mar-08

Jun-08

Sep-08

Dec-08

Mar-09

Jun-09

Sep-09

Dec-09

-

2,000

4,000

6,000

8,000

10,000

12,000

Investment Grade Non-Investment Grade

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

$70.0

$80.0

Q3 Q4 Q1 Q2 Q3 Q4

($ in

bill

ions

)

36

Gross Derivatives – Assets

$36.3B

$51.9B $50.6B

2008 2009

Changes in the Gross Derivative Balance is only impacted by two forces:- Commodity price volatility, which is market-based and not controlled by CEG- Change in Number of Contracts

Quarter-to-Quarter Change $15.6B $(1.3B) $(10.4B) $(12.9B) $(7.0B)

Change Due to:

Commodity Price Volatility $21.0B $19.0B $(5.5B) $(0.3B) $1.8B

Change in Number of Contracts $(5.4B) $(20.3B) $(4.9B) $(12.6B) $(8.8B)

$40.2B

$27.3B

$20.3B

Note: Subject to change pending filing of 2009 Form 10-K

37

Mark-to-Market Derivative Assets

Note: Subject to change pending filing of 2009 Form 10-K

Derivative Assets Subject to Mark-to-Market Accounting

Settlement Term

($ millions at 12/31/09) 2010 2011 2012 2013 2014 2015 Thereafter Fair Value

Level 1 $ 1.6 $ --

$ --

$ --

$ --

$ -- $ -- $ 1.6

Level 2 73.7 636.5 102.1 (18.1) (2.9) 0.1 1.3 792.7

Level 3 58.6 (197.9) (140.6) (12.8) 10.4 9.9 2.4 (270.0)

Total net derivative asset subject to MTM accounting $ 133.9 $ 438.6 $ (38.5) $ (30.9) $ 7.5 $ 10.0 $ 3.7 $ 524.3

Change in Net MTM Derivative Assets ($ in millions) Three Months Ended 12/31/09 Year Ended 12/31/09

Fair value beginning of period $ 738.6 $ 1,485.9

Origination gains -- --

Unrealized changes in fair value 20.9 (212.3)

Changes in valuation techniques -- --

Reclassification of settled contracts to realized 17.2 (265.4)

Total changes in fair value recorded in earnings 38.1 (477.7)

Changes in value of exchange-listed futures and options (258.1) 97.8

Net change in premiums on options 43.9 84.9

Contracts acquired -- (35.8)

Dedesignated contracts and other changes in fair value (38.2) (630.8)

Fair value at end of period $ 524.3 $ 524.3

Non-GAAP Appendix

38

Summary of Non-GAAP Measures

Slide(s) Where Used Slide Containing

Non-GAAP Measure in Presentation Most Comparable GAAP Measure Reconciliation

Adjusted EPS Reported GAAP EPS

YTD 2009 Actual 4, 11, 17 40-43

YTD 2008 Actual 11 40-43

Q109 Actual 17 40-43

Q209 Actual 17 40-43

Q309 Actual 17 40-43

Q409 Actual 17 40-43

EPS Guidance 15 40-43

BGE Gross Margin 19 Income from Operations / Net Income 44-45

Merchant Gross Margin 20 Income from Operations / Net Income 46-47

Adjusted Debt, Adjusted Equity, Adjusted Capitalization 14 Total Debt, Total Equity, Total Capitalization 48

Funds From Operations 14 Operating, Investing and Financing Cash Flows 49

39

Adjusted EPS 2009, 2008 and Quarterly – Consolidated

We exclude special items and certain economic, non-qualifying hedges because we believe that it is appropriate for investors to consider results excluding these items, in addition to our results in accordance with GAAP. We have also adjusted earnings to exclude synfuel results due to the potential volatility and phase-out of the tax credits. We believe such a measure provides a picture of our results that is comparable among periods since it excludes the impact of items, which may recur occasionally, but tend to be irregular as to timing and magnitude, thereby distorting comparisons between periods. However, investors should note that this non-GAAP measure involves judgment by management (in particular, judgments as to what is or is not classified as a special item). We also use this measure to evaluate performance and for compensation purposes. Effective in 2009, we are no longer adjusting our Reported GAAP EPS for synfuel earnings, due to the expiration of the tax credit, and non-qualifying hedges, which were related to activities conducted by our recently divested operations.

RECONCILIATION:CEG Consolidated 2008 2009

($ per share) Total Q1 09 Q2 09 Q3 09 Q4 09 Total

ACTUAL RESULTS:

Reported GAAP EPS (7.34)$ (0.62)$ 0.04$ 0.69$ 21.96$ 22.19$

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

(7.34) (0.62) 0.04 0.69 21.96 22.19

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

Gain on EDF J oint Venture - - - - 22.13 22.25

Merger Termination, Strategic Alternatives

and Other Transaction-Related Costs (6.72) (0.23) (0.04) (0.06) 0.08 (0.26)

Amortization of Basis Difference - - - - (0.09) (0.09)

Operations Being Divested - (0.93) (0.62) (0.31) - (1.86)

Impairment Losses and Other Costs (3.13) (0.17) (0.35) (0.14) (0.03) (0.69)

BGE Residential Customer Rate Credit - - - - (0.34) (0.34)

UniStar Nuclear Energy Results - (0.01) (0.02) (0.02) (0.03) (0.08)

Loss on Redemption of Zero Coupon Notes - - - - (0.05) (0.05)

Workforce Reduction Costs (0.07) (0.02) (0.01) (0.01) (0.01) (0.05)

Maryland Settlement - BGE Credit (0.62) - - - - -

Non-qualifying hedges (0.39) - - - - -

Synthetic fuel facility results 0.02 - - - - -

Total Special Items and Non-qualifying Hedges (10.91) (1.36) (1.04) (0.54) 21.66 18.83

Adjusted EPS 3.57$ 0.74$ 1.08$ 1.23$ 0.30$ 3.36$ NON-GAAP MEASURE

EARNINGS GUIDANCE

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

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

NOTE

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

EPS Before Discontinued Operations and

Cumulative Effects of Changes in

Accounting Principles

40

Adjusted EPS 2009, 2008 and Quarterly – Merchant


RECONCILIATION:Merchant 2008 2009


ACTUAL RESULTS:

Reported GAAP EPS (7.58)$ (1.02)$ 0.02$ 0.58$ 22.18$ 21.88$

Income from Discontinued Operations - High Desert - - - - - - GAAP MEASURES

(7.58) (1.02) 0.02 0.58 22.18 21.88

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

Gain on EDF J oint Venture - - - - 22.13 22.25

Merger Termination, Strategic Alternatives

and Other Transaction-Related Costs (6.72) (0.23) (0.04) (0.06) 0.08 (0.26)

Amortization of Basis Difference - - - - (0.09) (0.09)

Operations Being Divested - (0.93) (0.62) (0.31) - (1.86)

Impairment Losses and Other Costs (3.13) (0.17) (0.34) (0.14) - (0.64)

Loss on Redemption of Zero Coupon Notes - - - - (0.05) (0.05)

Workforce Reduction Costs (0.05) (0.02) (0.01) (0.01) (0.01) (0.05)

Non-qualifying hedges (0.39) - - - - -

Synthetic fuel facility results 0.02 - - - - -

Total Special Items and Non-qualifying Hedges (10.27) (1.35) (1.01) (0.52) 22.06 19.30


EARNINGS GUIDANCE



NOTE





41

Adjusted EPS 2009, 2008 and Quarterly – BGE


RECONCILIATION:BGE 2008 2009


ACTUAL RESULTS:

Reported GAAP EPS 0.21$ 0.41$ 0.06$ 0.14$ (0.16)$ 0.46$


0.21 0.41 0.06 0.14 (0.16) 0.46

Special Items:

BGE Residential Customer Rate Credit - - - - (0.34) (0.34)

Maryland Settlement - BGE Credit (0.62) - - - - -

Workforce Reduction Costs (0.02) - - - - -

Total Special Items (0.64) - - - (0.34) (0.34)


EARNINGS GUIDANCE



NOTE





42

Adjusted EPS 2009, 2008 and Quarterly – ONR


RECONCILIATION:Other Nonregulated 2008 2009


ACTUAL RESULTS:

Reported GAAP EPS 0.03$ (0.01)$ (0.04)$ (0.03)$ (0.06)$ (0.15)$


0.03 (0.01) (0.04) (0.03) (0.06) (0.15)

Special Items:

UniStar Nuclear Energy Results - (0.01) (0.02) (0.02) (0.03) (0.08)

Impairment Losses and Other Costs - - (0.01) - (0.03) (0.05)

Total Special Items - (0.01) (0.03) (0.02) (0.06) (0.13)

Adjusted EPS 0.03$ -$ (0.01)$ (0.01)$ -$ (0.02)$ NON-GAAP MEASURE

EARNINGS GUIDANCE



NOTE





43

2009 BGE Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy and to highlight the primary driver of earnings at our Regulated Utility. We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our BGE operating results from period to period.

GAAP to NONGAAP Walk2009 Notes: a b

BGE Gross Margin CategoriesBGE

GAAP

BGECustomer

CreditDCW

Impairment

Other Adjustments Below GM

Other Notes

Non-GAAP

Electric 980$ 95$ 1,075$ Gas 308 18 326 Total Regulated 1,288$ 113$ -$ -$ 1,401$

Operating & Maintenance (560) (3) (563)$ Depreciation & Amortization (262) (262) Taxes Other than Income Taxes (178) 178 cImpairments (20) 20Income from Operations N/AOther Revenue and Expense 26 (192) c,d (166) EBIT 410 410 Fixed Charges (139) 14 d (125) Income Before Income Taxes N/AIncome Tax expense (64) (45) (5) (113) Income from Continuing Operations N/APreference Stock Dividends (13) (13) NonControlling Interest 7 (7) Net Income 85$ 65$ 8$ -$ 158$

Amounts may not foot due to the effects of rounding

d Adjustment to reclassify: (1) $1.4 million of cash pool interest income from Other Income to Fixed Charges, (2) $17.5 million of rate stabilization income from Other Income to Fixed Charges, and (3) $(4.3) million of capitalized AFUDC from Fixed Charges to Other Income

a Adjustment to remove the BGE Customer Credit and related income and tax effects that management views as a special item.b Adjustment to remove the DCW Impairment charge and related income and tax effects that management views as a special item.c Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense.

Adjustments in Arriving at Non-GAAP

44

2008 BGE Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy and to highlight the primary driver of earnings at our Regulated Utility. We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our BGE operating results from period to period.

GAAP to NONGAAP Walk2008 Notes: a b

BGE Gross Margin Categories BGE GAAPMaryland Settlement

Credit

Maryland Settlement Credit -

Effective Tax


Other Notes

Non-GAAP

Electric 800 189$ 989$ Gas 330 330 Total Regulated 1,130$ 189$ -$ 1,318$

Operating & Maintenance (538) (3) (540)$ Workforce Reduction Costs (6) 6 e - Depreciation & Amortization (228) (228) Taxes Other than Income Taxes (175) 176 d - Income from Operations 183 Other Revenue and Expense 29 (195) d, c (166) EBIT N/A 385 Fixed Charges (140) 19 c (121) Income Before Income Taxes 72 Income Tax expense (21) (59) (16) (2) e (98) Income from Continuing Operations 51 Preference Stock Dividends (13) (13) Net Income 38$ 127$ (16)$ 4$ 153$

a Adjustment to remove the Maryland Settlement Credit charge and related income and other tax effects that management views as a special item.b Adjustment to remove the effective tax rate adjustment related to the Maryland Settlement Credit charge that management views as a special item.c Adjustment to move Interest Income recorded in Other Income to Fixed Charges (to show a fixed charge amount net of interest income).d Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. e Adjustment to remove workforce reduction costs that management views as a special item.



($ million)

45

2009 Merchant Gross Margin and Below Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Generation, Customer Supply, and Global Commodities). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

GAAP to NONGAAP Walk2009 Notes: a b c d e f g

Merchant Gross Margin Categories GAAP

Divestiture of International Commodities Operations

Divestiture of Downstream Gas Trading Operations

Upstream Asset Sale

Certain Operating Expenses

Gross Receipts

Tax Fly Ash

CENG Sale and Basis Difference

Other Adjustments Below GM Other Notes

Non-GAAP

Generation 1,976$ (30)$ 25$ 1,971$ Customer Supply 799 (31) 768

Global Commodities 185 71 21 6 283 Total 2,960$ 71$ 21$ 6$ (30)$ (31)$ 25$ -$ -$ 3,023$

Equity Investment Earnings 19 31 50$ Gain on Sale of Interest in CENG 7,446 (7,446) Net Loss on Divestitures (464) 359 111 (6) Operating Expenses (1,534) 17 16 30 (25) (1,498) Impairment Losses and Other Costs (98) 98 hWorkforce Reduction Costs (13) 13 iMerger Termination and Strategic Alternatives Costs (146) 146 jDepreciation, Depletion, and Amortization (250) (250) Accretion of Asset Retirement Obligation (62) (62) Taxes Other than Income Taxes (109) 31 78 kIncome from Operations 7,750 Other Income and Expense (169) (26) k,l,m,n,p,q (195) EBIT N/A 1,068 Fixed Charges (208) 25 o,p (183) Income Before Income Taxes 7,373 885 Income Tax expense (2,938) (171) (53) 2,978 (185) h,I,j,m,n,o,q (369) Income from Continuing Operations 4,435 516 Income from discontinued operations - - Noncontrolling interest (54) 54 l - Net Income 4,381$ 276$ 95$ -$ -$ -$ -$ (4,437)$ 203$ 516$

a Adjustment to remove the effect of the divestiture of our international commodities operations and uranium market participant from Non-GAAP gross margin and below gross margin measuresb Adjustment to remove the effect of the divestiture of our Houston-based downstream gas trading operations from Non-GAAP gross margin and below gross margin measuresc Adjustment to reclassify gain on sale of Upstream Gas properties to Non-GAAP gross margind Adjustment to reclassify operating expenses to Non-GAAP gross margine Adjustment to reclassify gross receipts tax from operating expenses to Non-GAAP gross marginf Adjustment to reclassify fly ash expense to Non-GAAP operating and maintenance expenseg Adjustment to remove Special Items (Gain on sale of interest in CENG and Amortization of basis difference in CENG) and related tax expense ($2,978m), which are not included in determining Merchant Below Gross Marginh Adjustment to remove Special Items (Impairment losses and other costs) and related tax benefit ($13m), which are not included in determining Merchant Below Gross Margini Adjustment to remove Special Items (Workforce reduction costs) and related tax benefit ($3m), which are not included in determining Merchant Below Gross Marginj Adjustment to remove Special Items (Merger termination and strategic alternatives costs) and related tax benefit ($132), which are not included in determining Merchant Below Gross Margink Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expensel Adjustment to reflect the fact that management views Noncontrolling Interests as Other Expensem Adjustment to remove Special Items (Nuclear Decommissioning Trust Fund Impairments of $61m) and related tax benefit ($15m), which is not included in determining Merchant Below Gross Marginn Adjustment to remove Special Items (Credit facility amendment and termination fees of $61m) and related tax benefit ($24m), which is not included in determining Merchant Below Gross Margino Adjustment to remove Special Items (Loss on retirement of bond of $16m) and related tax benefit ($6m), which is not included in determining Merchant Below Gross Marginp Adjustment to reclassify Interest Income ($8m) recorded in Other Income and Expense to Fixed Charges (to show a net fixed charge amount net of interest income)q Adjustment to reclassify certain tax expense ($8m) that management views as Other Expense


46

2008 Merchant Gross Margin and Below Gross Margin

We utilize the non-GAAP financial measure of Gross Margin to highlight the relationship between the costs of and prices for energy in our Merchant Energy business categories (i.e., Generation, Customer Supply, and Global Commodities). We also make certain adjustments to items below gross margin through net income including EBIT. We believe these non-GAAP measures help investors to better understand the changes in the level of our Merchant Energy operating results from period to period.

GAAP to NONGAAP Walk2008 Notes: a b c d e f g h i

Merchant Gross Margin Categories GAAPNonqualifying

Hedges

Certain Operating Expenses

Gross Receipts Tax / Aggregator

Fees Fly AshDecommissioning

Revenue CAIR

Upstream - Cash Flow

Hedge Reclass

Sale of Upstream

Gas Properties Synfuels


Other Notes

Non-GAAP

Generation 1,919$ (34)$ 26$ (19)$ 1,891$ Customer Supply 765 (77) 688 Global Commodities 215 115 25 (4) 24 (1) 373 Total 2,899$ 115$ (34)$ (77)$ 26$ (19)$ 25$ (4)$ 24$ (1)$ -$ 2,952$

Equity Method Earnings 82$ (4) 78$ Operating & Maintenance (1,730) 34 37 (26) (1,685) Impairment Losses on Long Lived Assets & Other Costs (742) 742 k - Workforce Reduction Costs (15) 15 l - Merger and Other Strategic Alternative Costs (1,204) 1,204 m - Depreciation & Amortization (287) 2 (285) Asset Retirement Obligation (68) (68) Taxes Other than Income Taxes (124) 40 84 j - Income from Operations (1,190) Gain on Sales of Upstream Gas Assets 26 (25) - Other Revenue and Expense (120) 19 2 (1) 73 j, n, o, p (27) EBIT N/A 965 Fixed Charges (191) 5 12 n (174) Income Before Income Taxes (1,475) 790 Income Tax expense 100 (45) (9) 2 (1) (5) (350) k, l, o (308) Income from Continuing Operations (1,375) 482 Income from discontinued operations - - Noncontrolling Interest 17 (17) p - Net Income (1,357)$ 70$ -$ -$ -$ -$ 15$ (2)$ -$ (4)$ 1,763$ 482$

a Adjustment to remove economic, nonqualifying hedges of gas transport and storage contracts.b Adjustment to reclassify operating expenses to Non-GAAP gross margin.c Adjustment to reclass gross receipts tax and aggregator fees from operating expenses to Non-GAAP gross margin.d Adjustment to reclass fly ash expenses to Non-GAAP operating and maintenance expense.e Adjustment to remove decommissioning revenues from non-GAAP gross margin measure and include in Other Income. The offsetting decommissioning expense was recorded in accretion of asset retirement obligations.f Adjustment to remove Special Item and related tax benefit, which relates to the write-down of our SO2 and NOx emission allowance inventory to reflect market prices at December 31, 2008.g Adjustment to remove Special Item and related tax benefit, which relates to the reclassification of cash-flow hedges (from the impaired Upstream Gas properties) with a pre-tax net gain deferred in Accumulated other Comprehensive Loss into Revenues. h Adjustment to reclassify gain on sale of Upstream Gas properties to Non-GAAP gross margini Adjustment to remove Synfuel earningsj. Adjustment to reflect the fact that management views Taxes Other Than Income Taxes as Other Expense. k Adjustment to remove Special Items (Impairment losses on long lived assets and fly ash class action settlement) and related tax benefit ($270 million), which are not included in determining Merchant Below Gross Marginl Adjustment to remove Special Items (workforce reduction) and related tax benefit ($6 million), which are not included in determining Merchant Below Gross Marginm Adjustment to remove Special Items (merger and strategic alternative costs), which are not included in determining Merchant Below Gross Marginn Adjustment to move Interest Income recorded in Other Income / Expense to Fixed Charges (to show a fixed charge amount net of interest income).o Adjustment to remove Nuclear Decommission Trust Fund Losses (Special Items of $153 million) and related tax benefit ($77 million), which are not included in determining Merchant Below Gross Marginp Adjustment to reclassify Noncontrolling Interest to Other Revenue and Expense



($ million)

47

Adjusted Debt, Equity, and Capitalization

We provide the non-GAAP measures of Adjusted Debt, Adjusted Equity, and Adjusted Capitalization as management believes these measures provide investors useful information on our leverage because it is consistent with the evaluation performed by rating agencies.

RECONCILIATION: December 31, 2009

BGE Merchant and Other CEG

Cash Balance 322.8$ 3,117.2$ 3,440.0$ NON-GAAP MEASURE

Total long-term debt 2,141.4$ 2,672.6$ 4,814.0$ Current portion of long-term debt 56.5 0.4 56.9

Long-term debt, gross 2,197.9 2,673.0 4,870.9 GAAP MEASURES

Short-term borrowings 46.0 - 46.0 Total Debt per Balance Sheet 2,243.9 2,673.0 4,916.9

50% Equity credit to trust preferred securities (128.9) - (128.9) 50% Equity credit for 60-year hybrid debt securities - (225.0) (225.0) BGE Securitization Debt (510.9) - (510.9) S&P imputed debt 331.5 1,632.1 1,963.6 Total Adjusted Debt 1,935.6 4,080.1 6,015.7 NON-GAAP MEASURE

Total equity per balance sheet 2,146.4 6,816.0 8,962.4 GAAP MEASURE50% Equity credit to trust preferred securities 128.9 - 128.9 50% Equity credit for 60-year hybrid debt securities - 225.0 225.0 FAS 133 AOCI (0.6) 581.3 580.7 Total Adjusted Equity 2,274.7 7,622.3 9,897.0 NON-GAAP MEASURE

Total Adjusted Capitalization 4,210.3$ 11,702.4$ 15,912.7$ NON-GAAP MEASURE

48

Funds From Operations

The non-GAAP financial measure of Funds from Operations (FFO) is a non-GAAP measure that approximates recurring cash flows from operations exclusive of all non-cash items and working capital. We utilize this non-GAAP measure as it is helpful in understanding our recurring operating cash performance as earnings generally include large non-cash items.

GAAP to NONGAAP Walk2009

RECONCILIATION: BGE Merchant and Other CEG

Net cash provided by operating activities (GAAP Measure) 815 3,576 4,391

LESS: Changes in working capital (excluding derivative assets and liabilities) and other (5) (2,094) (2,099)

ADD BACK: Defined benefit expense not allocated for cash flow purposes (165) (122) (287)

ADD: OLA Depreciation (S&P calculated) - 274 274

ADD: Pension adjustment (S&P analysis) 93 67 160

SUBTRACT: Capitalized interest (excluding BGE borrowed funds AFC) - (83) (83)

SUBTRACT: Repayment of securitized debt (54) - (54)

Funds from operations (FFO - NONGAAP Measure) 684 1,618 2,302

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