Use these links to rapidly review the documentTABLE OF CONTENTS

Table of Contents

---

---

UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K



ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year endedDECEMBER 31, 2008

Commission
file number

Exact name of registrant as specified in its charter

IRS Employer Identification No.1-12869

CONSTELLATION ENERGY GROUP, INC.

52-19646111-1910

BALTIMORE GAS AND ELECTRIC COMPANY

52-0280210


MARYLAND(States of incorporation)

100 CONSTELLATION WAY,            BALTIMORE,
MARYLAND                21202(Address of principal executive offices)                (Zip Code)

410-470-2800(Registrants' telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

Title of each class



Name of each exchange on
which registeredConstellation Energy Group, Inc. Common StockWithout Par Value

)

New York Stock Exchange
Chicago Stock ExchangeConstellation Energy Group, Inc. Series A Junior Subordinated Debentures
  
6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company

)

New York Stock Exchange


SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:Not Applicable

Indicate
by check mark if Constellation Energy Group, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ý    No o.

Indicate by check mark if Baltimore Gas and Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ý    No o.

Indicate by check mark if Constellation Energy Group, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o    No ý.

Indicate by check mark if Baltimore Gas and Electric Company is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o    No ý.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past
90 days.    Yes ý    No o.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K.    o

Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a
smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large
accelerated filer ý        Accelerated filer o        Non-accelerated
filer o        Smaller reporting company o

Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer or a
smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large
accelerated filer o        Accelerated filer o        Non-accelerated
filer
ý        Smaller reporting company o

Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act)
Yes o    No ý

Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act)
Yes o    No ý

Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2008
was approximately $14,585,929,431 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE
199,127,544 SHARES OUTSTANDING ON JANUARY 30, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

Part of Form 10-K

Document Incorporated by ReferenceIII

Certain sections of the Proxy Statement for the 2009 Annual Meeting of Shareholders for Constellation Energy Group, Inc.


Baltimore Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of
Form 10-K and is therefore filing this Form in the reduced disclosure format.

---

---

---





Table of Contents



TABLE OF CONTENTS



PageForward Looking Statements


1PART IItem 1



Business


2Overview


2Merchant Energy Business


5Baltimore Gas and Electric Company


12Other Nonregulated Businesses


15Consolidated Capital Requirements


16Environmental Matters


16Employees


19Item 1A



Risk Factors


20Item 2



Properties


27Item 3



Legal Proceedings


29Item 4



Submission of Matters to Vote of Security Holders


29Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)


29PART IIItem 5



Market for Registrant's Common Equity, Related Shareholder Matters, Issuer Purchases of Equity Securities, and Unregistered Sales of Equity and Use of
Proceeds


30Item 6



Selected Financial Data


32Item 7



Management's Discussion and Analysis of Financial Condition and Results of Operations


34Item 7A



Quantitative and Qualitative Disclosures About Market Risk


79Item 8



Financial Statements and Supplementary Data


80Item 9



Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


157Item 9A and 9A(T)



Controls and Procedures


157Item 9B



Other Information


157PART IIIItem 10



Directors, Executive Officers and Corporate Governance


157Item 11



Executive Compensation


157Item 12



Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters


157Item 13



Certain Relationships and Related Transactions, and Director Independence


158Item 14



Principal Accountant Fees and Services


158PART IVItem 15



Exhibits and Financial Statement Schedules


159Signatures


165


---





Table of Contents

Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of
1934. Sometimes these statements will 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 and projections are not guarantees of our future performance and are subject to risks,
uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include,
but are not limited to:



Given
these uncertainties, you should not place undue reliance on these forward looking statements. Please see the other sections of this report and our other periodic reports filed with
the Securities and Exchange Commission (SEC) for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report.

Changes
may occur after that date, and neither Constellation Energy nor BGE assumes responsibility to update these forward looking statements.

1

---





Table of Contents

PART I

Item 1. Business

Overview

Constellation Energy is an energy company that includes a merchant energy business and BGE, a regulated electric and gas public
utility in central Maryland. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are
to BGE.

Our
merchant energy business is primarily a competitive provider of energy-related products and services for a variety of customers. It develops, owns, and operates electric generation
facilities located in various regions of the United States. Our merchant energy business focuses on serving the energy and capacity requirements (load-serving) of, and providing other
energy products and risk management services for, various customers.

BGE
is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and
all or part of 10 counties in central Maryland. BGE was incorporated in Maryland in 1906.

Our
other nonregulated businesses:



As
a capital- and asset-intensive business, Constellation Energy was significantly impacted by events in the financial and credit markets during 2008. This has resulted in substantial
ongoing changes to our business.

Over
the past few years, our merchant energy business, which includes our trading operations and international commodities operation, grew rapidly. As that business grew, so too did its
need for capital, particularly to fund the business' collateral requirements. We had previously met these collateral requirements through the use of cash and lines of credit, and we believed that we
could meet any unexpected short-term capital needs by maintaining a significant amount of available liquidity, primarily from our unused credit facilities. Furthermore, by maintaining an
investment grade credit rating, we believed we would continue to be able to access the capital markets if additional liquidity needs arose.

The
growth of our merchant energy business and its increased need for collateral, coupled with significant volatility in commodity prices in 2008, required us to post substantial amounts
of incremental collateral to our counterparties. The asymmetrical nature of the Customer Supply business' collateral posting requirements compounded the magnitude of the problem, negatively impacting
our overall liquidity. We discuss the asymmetrical nature of our collateral in more detail inItem 7. Management's Discussion and
AnalysisCollateralsection.

To
address these liquidity issues, in 2008, we explored a series of strategic initiatives to improve our liquidity and reduce our business risk. In the first half of 2008, we began to
pursue the sale or joint venturing of our highly capital-intensive commodities business based on the concern that our balance sheet could not support the significant growth of this business
long-term. We embarked on a process and solicited bids from interested parties and although interest levels were high, following the collapse of Bear Stearns and the significant
difficulties encountered by other major financial institutions, we determined we would not get reasonable value for our business. In August 2008, we began efforts to sell our upstream gas properties
and our international commodities operation, which includes our coal sourcing, freight, power, natural gas, uranium, and emissions marketing activities outside the United States. In November 2008, we
announced we had begun efforts to sell our gas trading operation. We have made progress on many of these initiatives as discussed in more detail in the Divestituressection.

In
September 2008, a rapid and extreme increase in volatility of U.S. and global credit and capital markets caused us to face severe, near-term uncertainty about our ability
to maintain sufficient liquidity to continue operating our business. The rating agencies downgraded Constellation Energy's credit ratings because of concerns over our liquidity. The downgrades, in
turn, required us to post additional collateral assurance to some of our counterparties, and, since we could not access the capital markets, this further reduced our available liquidity. At that time,
we had not made significant progress with our strategic initiatives to generate substantial reductions in our collateral requirements or substantial improvements in our liquidity. As a result, we
sought an immediate, substantial investment to ensure our ability to continue operating our business, and in mid-September we ultimately agreed to a transaction with MidAmerican Energy
Holdings Company (MidAmerican) that involved an immediate $1 billion preferred equity investment by MidAmerican in us, followed by an all cash sale of our company to MidAmerican for
$4.7 billion. In early December 2008, we received an unsolicited offer from EDF Group and related entities

2

---



Table of Contents

(EDF)
to acquire a membership interest in our nuclear generation and operation business. Our Board of Directors determined the EDF proposal to be in the best interests of our shareholders. Therefore,
on December 17, 2008, we and MidAmerican terminated the planned transaction, and we simultaneously entered into a series of transactions with EDF.

The
EDF transactions do not involve the sale of Constellation Energy, but rather the sale of a membership interest in our nuclear generation and operation business resulting in the
Company continuing to operate on a standalone basis. The transactions that we agreed to with EDF include the following:



For
additional information related to these transactions with MidAmerican and EDF, seeNote 15 to Consolidated Financial
Statements. For additional information related to the issuance of the Series B Preferred Stock, seeNote 9 to Consolidated Financial
Statements.

Over
the next one to two years, we expect to be in a transition period during which we will focus on executing the following objectives that we believe will strengthen the Company:



We
believe that focusing on the near-term execution of the above objectives will allow us to preserve the flexibility to respond to long-term opportunities. For a
further discussion of the above matters and how they have impacted us and our strategy, please refer toItem 7. Management's Discussion and
Analysis.

Divestitures

In 2009, we made progress on many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business
risk. These initiatives included selling our international commodities operation, which primarily includes our coal sourcing, freight, power, natural gas, uranium, and emissions marketing activities;
our gas trading operation; and our upstream gas properties.

3

---



Table of Contents

In
January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. In February 2009, we entered into a definitive agreement to sell
our Houston-based gas trading operation. Simultaneously, we signed a letter of intent to enter into a related transaction with an affiliate of the buyer under which that company would provide us with
the gas supply needed to support our retail gas customer supply business, while reducing our credit requirements. We expect that both of these sales will close by the end of the second quarter of
2009, subject to certain regulatory approvals and other standard closing conditions. Upon closing of these transactions, we expect to recognize an aggregate pre-tax loss of not more than
$200 million based on current commodity prices. The actual amount of the loss will be affected by the final consideration exchanged, which is based on the timing of the close, and by changes in
commodity prices. The impact on cash is not expected to be material.

Collectively,
we expect both divestitures to return to us approximately $1 billion of currently posted collateral. In addition, we expect these divestitures to further reduce our
downgrade collateral requirements by approximately $400 million. These reductions are based on current commodity prices, the final terms of the transactions, and the timing of collateral to be
returned up to the close of the transactions, and, as a result, are subject to change. We discuss our downgrade collateral requirements inItem 7. Management's
Discussion and AnalysisCollateralsection.

While
we sold certain of our upstream gas properties in 2008, we continue to evaluate the sale of our remaining upstream gas properties while monitoring market conditions for
opportunities to obtain appropriate value for these upstream gas properties. Unlike our international commodities operation and our gas trading operation, there are no material collateral needs
associated with the remaining properties, minimizing the need to divest these immediately.

Operating Segments

The percentages of revenues, net income (loss), and assets attributable to our operating segments are shown in the tables below. We
present information about our operating segments, including certain other items, inNote 3 to Consolidated Financial Statements.

Unaffiliated RevenuesMerchant
Energy

Regulated
Electric

Regulated
Gas

Holding
Company
and Other
Nonregulated2008


80
%

14
%

5
%

1
%2007


83


12


4


12006


83


11


5


1




Net Income (Loss) (1)Merchant
Energy

Regulated
Electric

Regulated
Gas

Holding
Company
and Other
Nonregulated2008


(103
)%


%

3
%


%2007


83


12


3


22006


77


16


5


2




Total AssetsMerchant
Energy

Regulated
Electric

Regulated
Gas

Holding
Company
and Other
Nonregulated2008 (2)


62
%

21
%

6
%

11
%2007


73


20


6


12006


75


17


6


2


4

---



Table of Contents

Merchant Energy Business

Introduction

Our merchant energy business generates and sells power and gas to both regulated and nonregulated wholesale and retail marketers and
consumers of energy products, manages all commodity price risk for our nonregulated businesses, enters into structured energy contracts, and trades energy. We conduct these activities across all
regions in the United States and internationally.

Our
merchant energy business includes:



In
2008, we began pursuing a number of strategic initiatives that will impact our merchant energy business in 2009 and future years. We discuss these strategic initiatives and how they
have impacted our merchant energy business segment and our strategy inItem 7. Management's Discussion and Analysis. We also discuss certain
asset and operations divestitures in theDivestituressection.

During
2008, our merchant energy business:



We
analyze our merchant energy business in terms of Generation, Customer Supply and Global Commodities activities.



Generation

We own, operate, and maintain fossil, nuclear, and renewable generating facilities and hold interests in qualifying facilities, and
power projects in the United States and Canada totaling 9,136 MW. We also provide operation and maintenance services, including testing and start-up, to owners of electric generating
facilities. The output of these plants is managed by our Global Commodities operation and is hedged through a combination of power sales to wholesale and retail market participants. Our merchant
energy business meets the load-serving requirements of various contracts using the output from our generating fleet and from purchases in the wholesale market.

We
present details about our generating properties inItem 2. Properties.

Nuclear

The output of our nuclear facilities over the past three years is presented in the following table:

Calvert Cliffs

Nine Mile Point

GinnaMWH

Capacity
Factor

MWH *

Capacity
Factor

MWH

Capacity
Factor(MWH in millions)2008


14.7


96
%

12.8


94
%

4.7


94
%2007


14.3


94


12.3


90


4.9


982006


13.8


90


12.8


93


4.1


93


We sell a significant portion of the output from our Nine Mile Point Nuclear Station (Nine Mile Point) and our R.E. Ginna Nuclear Plant (Ginna) under
unit-specific power purchase agreements. We discuss these arrangements on the next page. Our Global Commodities operation manages the remainder of our generation output.

5

---



Table of Contents

In
December 2008, we entered into the Investment Agreement with EDF under which EDF will purchase a 49.99% membership interest in our nuclear generation and operation business, which
owns our three nuclear facilities. We discuss the Investment Agreement in more detail inNote 15 to Consolidated Financial Statements.

Calvert
Cliffs

We
own 100% of Calvert Cliffs Unit 1 (873 MW) and Unit 2 (862 MW). Unit 1 entered service in 1974 and is licensed to operate until 2034. Unit 2 entered service in 1976 and
is licensed to operate until 2036.

Nine
Mile Point

We
own 100% of Nine Mile Point Unit 1 (620 MW) and 82% of Unit 2 (933 MW of Unit 2's total 1,138 MW). The remaining interest in Nine Mile Point Unit 2 is owned by the Long
Island Power Authority (LIPA). Unit 1 entered service in 1969 and is licensed to operate until 2029. Unit 2 entered service in 1988 and is licensed to operate until 2046.

We
sell 90% of our share of Nine Mile Point's output to the former owners of the plant at an average price of nearly $35 per megawatt-hour (MWH) under agreements that
terminate between 2009 and 2011. The agreements are unit contingent (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources).
The remaining 10% of our share of Nine Mile Point's output is managed by our Global Commodities operation and sold into the wholesale market.

After
termination of the power purchase agreements, a revenue sharing agreement with the former owner of the plant will begin and continue through 2021. Under this agreement, which
applies only to our ownership percentage of Unit 2, a predetermined strike price is compared to the market price for electricity. If the market price exceeds the strike price, then 80% of this excess
amount is shared with the former owners of the plant. The average strike price for the first year of the revenue sharing agreement is $40.75 per MWH. The strike price increases two percent annually
beginning in the second year of the revenue sharing agreement. The revenue sharing agreement is unit contingent and is based on the operation of the unit.

We
exclusively operate Unit 2 under an operating agreement with LIPA. LIPA is responsible for 18% of the operating costs (including decommissioning costs) and construction costs of Unit
2 and has representation on the Nine Mile Point Unit 2 management committee, which provides certain oversight and review functions.

Ginna

We
own 100% of the Ginna nuclear facility. Ginna consists of a 581 MW reactor that entered service in 1970 and is licensed to operate until 2029. We sell 90% of the plant's
output and capacity to the former owner for 10 years ending in 2014 at an average price of $44.00 per MWH under a long-term unit-contingent power purchase agreement. The
remaining output is managed by our Global Commodities operation and sold into the wholesale market.

Qualifying Facilities and Power Projects

We hold up to a 50% voting interest in 18 operating energy projects that consist of electric generation (primarily relying on alternative fuel
sources), fuel processing, or fuel handling facilities. Sixteen of the electric generation projects are considered qualifying facilities under the Public Utility Regulatory Policies Act of 1978. Each
electric generating plant sells its output to a local utility under long-term contracts.

Customer Supply

We are a leading supplier of energy products and services to wholesale and retail electric and natural gas customers.

In
2008, our wholesale competitive supply operation served approximately 12,500 peak MWs of wholesale full requirements load-serving products. During 2008, our retail
competitive supply activities served approximately 14,100 MW of peak load and approximately 407,000 mmBTUs of natural gas.

Our
wholesale customer supply operation structures transactions that serve the full energy and capacity requirements of various customers such as distribution utilities, municipalities,
cooperatives and retail aggregators that do not own sufficient generating capacity or in-house supply functions to meet their own load requirements.

Our
retail customer supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and
services to retail, commercial, industrial, and governmental customers. Contracts with these customers generally extend from one to ten years, but some can be longer. To meet our customers'
load-serving requirements, our merchant energy business obtains energy from various sources, including:



6

---



Table of Contents



Global Commodities

Our Global Commodities operation manages contractually owned physical assets, including generation facilities, natural gas
properties, international coal sourcing and freight operations, provides risk management services and uranium marketing services, and trades energy and energy-related commodities. This operation
provides the wholesale risk management function for our Generation and Customer Supply operations, as well as structured products and energy investment activities and includes our merchant energy
business' actual hedged positions with third parties.

Structured Products

Our Global Commodities operation uses energy and energy-related commodities and contracts in order to manage our portfolio of energy purchases and
sales to customers through structured transactions. Our Global Commodities operation assists customers with customized risk management products in the power, gas, coal, and freight markets
(e.g., generation tolls, gas transport and storage, and global coal and freight logistics).

Energy Investments

Our Global Commodities operation has investments in energy assets that primarily include coal sourcing activities, a joint interest in an entity that
owns dry bulk cargo vessels and natural gas services. We discuss each of these investments below.

Coal and International Services

We participate in global coal sourcing activities by providing coal and coal-related logistical services for the variable or fixed supply
needs of global customers. We own a 50% interest in a shipping joint venture that owns and operates five freight ships for the delivery of coal and other dry bulk freight products. In 2008, we
delivered approximately 25.4 million tons of coal to global customers and to our own
generation fleet. Additionally, we entered into power, natural gas, freight, uranium marketing, and emissions transactions outside of the United States.

Natural Gas Services

Our Global Commodities operation includes upstream (exploration and production) and downstream (transportation and storage) natural gas operations.
Our upstream activities include the acquisition, development, exploration, and exploitation of natural gas properties, as well as an approximately 28.5% interest in Constellation Energy
Partners LLC (CEP), a limited liability company that we formed. CEP is principally engaged in the acquisition, development, and exploitation of natural gas properties. Our downstream activities
include providing natural gas to various customers, including large utilities, commercial and industrial customers, power generators, wholesale marketers, and retail aggregators.

In
2008, 2007, and 2006, we acquired working interests in gas producing fields. We discuss these acquisitions in more detail inNote 15 to Consolidated
Financial Statements. In 2008, we divested working interests in certain of our gas producing fields. We discuss these divestitures in more in detail in Note 2 to Consolidated Financial
Statements.

Portfolio Management and Trading

We trade energy and energy-related contracts and commodities and deploy risk capital in the management of our portfolio. These activities are managed
through daily value at risk and stop loss limits and liquidity guidelines, and could have a material impact on our financial results.

In
managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the
timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

We
use both derivative and nonderivative contracts in managing our portfolio of energy sales and purchase contracts. Although a substantial portion of our portfolio is hedged, we are
able to identify opportunities to deploy risk capital to increase the value of our accrual positions, which we characterize as portfolio management.

Active
portfolio management is intended to allow our merchant energy business to:



We
discuss the impact of our trading activities and value at risk in more detail inItem 7. Management's Discussion and Analysis.

Our
portfolio management and trading activities involve the use of physical commodity inventories and a variety of instruments, including:



7

---



Table of Contents



Through
the third quarter of 2008, our portfolio management and trading activities increased due to the significant growth in scale of our customer supply, energy investments, and
structured products operations. However, in the fourth quarter of 2008, we began to take steps to reduce the risk and scale of our portfolio management and trading activities. Energy trading
activities will be scaled back and will be used primarily to hedge our generation assets and Customer Supply operations. All of these efforts will materially reduce portfolio management and trading
activities' contribution to our future operating results.

Fuel Sources

Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2008 and our generation based
on actual output by fuel type in 2008 were as follows:

Fuel

Capacity
Owned

GenerationNuclear


42
%

63
%Coal


30


32Natural Gas


11


1Oil


8


Renewable and Alternative (1)


5


4Dual (2)


4





We discuss our risks associated with fuel in more detail inItem 7. Management's Discussion and AnalysisRisk
Management.

Nuclear

The supply of fuel for nuclear generating stations includes the:



We
have commitments that provide for sufficient quantities of uranium (concentrates and uranium hexafluoride), enrichment requirements, and the fabrication of fuel assemblies to meet
expected requirements for the next several years at our Calvert Cliffs, Nine Mile Point, and Ginna nuclear generating facilities.

The
nuclear fuel markets are competitive, and prices can be volatile; however, we do not anticipate any significant problems in meeting our future supply requirements.

Storage of Spent Nuclear FuelFederal Facilities

One of the issues associated with the operation and decommissioning of nuclear generating facilities is disposal of spent nuclear fuel. There are no
facilities for the reprocessing or permanent disposal of spent nuclear fuel currently in operation in the United States, and the Nuclear Regulatory Commission (NRC) has not licensed any such
facilities. The Nuclear Waste Policy Act of 1982 (NWPA) required the federal government, through the Department of Energy (DOE), to develop a repository for the disposal of spent nuclear fuel and
high-level radioactive waste.

As
required by the NWPA, we are a party to contracts with the DOE to provide for disposal of spent nuclear fuel from our nuclear generating plants. The NWPA and our contracts with the
DOE require payments to the DOE of one tenth of one cent (one mill) per kilowatt hour on nuclear electricity generated and sold to pay for the cost of long-term nuclear fuel storage and
disposal. We continue to pay those fees into the DOE's Nuclear Waste Fund for our nuclear generating facilities. The NWPA and our contracts with the DOE required the DOE to begin taking possession of
spent nuclear fuel generated by nuclear generating units no later than January 31, 1998.

The
DOE has stated that it may not meet that obligation until 2020 at the earliest. This delay has required that we undertake additional actions and incur costs to provide
on-site fuel storage at our nuclear generating facilities, including the installation of on-site dry fuel storage capacity as described in more detail below.

In
2004, complaints were filed against the federal government in the United States Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual
obligation to begin disposing of spent nuclear fuel by January 31, 1998. These cases are currently stayed, pending litigation in other related cases.

In
connection with our purchases of Nine Mile Point and Ginna, all of the former owners' rights and obligations related to recovery of damages for DOE's failure to meet its contractual
obligations were assigned to us. However, we have an obligation to reimburse the former owner of Ginna for up to $10 million of any recovered damages for such claims.

Storage of Spent Nuclear FuelOn-Site Facilities

Calvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage installation that expires in 2012.
Sufficient storage capacity exists within the plant and currently installed independent spent fuel

8

---



Table of Contents

storage
installation modules to be able to contain the full contents of the core until 2015. Efforts are currently under way to renew the independent spent fuel installation license and expand its
capacity to accommodate operations through 2034. Nine Mile Point and Ginna are developing independent spent fuel storage installations at each of those facilities, which we expect to be completed in
2012 and 2010, respectively. Nine Mile Point and Ginna have sufficient storage capacity within the plant until the expected completion of the on-site independent spent fuel storage
installations.

Cost for Decommissioning Nuclear Facilities

We are obligated to decommission our nuclear power plants after these plants cease operation. Our nuclear decommissioning trust funds and the
investment earnings thereon are restricted to meeting the costs of decommissioning the plants in accordance with NRC regulations and relevant state requirements. We develop our decommissioning trust
fund strategy based on estimates of the costs to perform the decommissioning and the timing of incurring those costs. When developing our estimates of future fund earnings, we consider our asset
allocation investment strategy, rates of return earned historically, and current market conditions.

Our
nuclear decommissioning trust fund assets are as follows:

At December 31, 2008Calvert Cliffs

$
346.9Nine Mile Point


460.3Ginna


199.1Total

$
1,006.3


Every two years, the NRC requires us to demonstrate reasonable assurance that funds will be available to decommission the sites. Our next NRC submittal will occur
in March 2009. Due to recent declines in the financial markets, the fair value of our trust funds decreased $324.5 million, net of $18.7 million of contributions made to the trusts,
during 2008. As a result of this decline, the NRC may require us to provide additional financial assurance for certain of our plants' decommissioning trusts. Previously, we have provided parental
guarantees as additional financial
assurance, but alternatively, the NRC could require other forms of financial assurance, including letters of credit, surety bonds, or additional cash contributions to the trusts.

Decommissioning
activities are currently projected to be staged through 2083. Any changes in the costs or timing of decommissioning activities, or changes in the fund earnings, could
affect the adequacy of the funds to cover the decommissioning of the plants, and if there were to be a shortfall, we would have to provide additional funding.

Calvert
Cliffs

When
BGE transferred all of its nuclear generating assets to our merchant energy business, it also transferred the funds accumulated to pay for decommissioning Calvert
Cliffs. In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Public Service Commission of Maryland
(Maryland PSC), and certain State of Maryland officials. The settlement agreement became effective on June 1, 2008. Pursuant to the terms of the settlement agreement, BGE customers will be
relieved of the potential future liability for decommissioning Calvert Cliffs Unit 1 and Unit 2. BGE will continue to collect the $18.7 million annual nuclear decommissioning charge from all
electric customers through 2016 and continue to rebate this amount to residential electric customers, as previously required by Maryland Senate Bill 1 which was enacted in June 2006. We discuss the
Maryland settlement agreement in more detail inNote 2 to Consolidated Financial Statements.

Nine
Mile Point

The
sellers of Nine Mile Point transferred a $441.7 million decommissioning trust fund to us at the time of sale. In return, we assumed all liability for the costs to
decommission Unit 1 and 82% of the costs to decommission Unit 2.

Ginna

The
seller of Ginna transferred $200.8 million in decommissioning funds to us. In return, we assumed all liability for the costs to decommission the unit.

Coal

We purchase the majority of our coal for electric generation under supply contracts with mining operators, and we acquire the remainder in the spot
or forward coal markets. We believe that we will be able to renew supply contracts as they expire or enter into contracts with other coal suppliers. Our primary coal-burning facilities
have the following requirements:

Approximate
Annual Coal
Requirement
(tons)Brandon ShoresUnits 1 and 2 (combined)


3,500,000C. P. CraneUnits 1 and 2 (combined)


850,000H. A. WagnerUnits 2 and 3 (combined)


1,100,000


9

---



Table of Contents

We receive coal deliveries to these facilities by rail and barge. Over the past few years, we expanded our coal sources through a variety of methods, including
restructuring our rail contracts, increasing the range of coals we can consume, and finding potential other coal supply sources including limited shipments from various international sources. While we
primarily use coal produced from mines located in central and northern Appalachia, we are capable of switching to coal from the Western United States or imported coal to manage our coal supply. The
timely delivery of coal together with the maintenance of appropriate levels of inventory is necessary to allow for continued, reliable generation from these facilities.

As
discussed in theEnvironmental Matterssection, our Maryland coal-fired generating facilities must comply with the
requirements of the Maryland Healthy Air Act (HAA), which requires reduction of sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury emissions. We are installing emission
control equipment at each of our Maryland coal-fired facilities. The new equipment and HAA emission reduction requirements will influence the characteristics of the coals that we burn in
the future.

All
of the Conemaugh and Keystone plants' annual coal requirements are purchased by the plant operators from regional suppliers on the open market. The sulfur restrictions on coal are
approximately 2.3% for the Keystone plant and approximately 5.3% for the Conemaugh plant. The Keystone owners are installing emission control equipment at Keystone which will result in a sulfur
restriction of 5.3%. Although we expected the Keystone and Conemaugh facilities would have to comply with Pennsylvania mercury regulations beginning in 2010, in January 2009, the Pennsylvania
Commonwealth Court held that those regulations were invalid based on a February 2008 federal court decision that struck down the Federal Clean Air Mercury Rule (CAMR). The Commonwealth of Pennsylvania
has indicated that it may appeal the court's decision. At this time, we cannot predict the ultimate outcome of these proceedings or its effect on our financial results.

The
annual coal requirements for the ACE, Jasmin, and Poso plants, which are located in California, are supplied under contracts with mining operators. These plants are restricted to
coal with sulfur content less than 4.0%.

The
primary fuel source for Panther Creek and Colver generating facilities is waste coal. These facilities meet their annual requirements through existing reserves of mined and processed
waste coal and through supply agreements with various terms.

All
of our coal requirements reflect historical generating levels. The actual fuel quantities required can vary substantially from historical levels depending upon the relationship
between energy prices and fuel costs, weather conditions, and operating requirements. However, we believe that we will be able to obtain adequate quantities of coal to meet our requirements.

Gas

We purchase natural gas, storage capacity, and transportation, as necessary, for electric generation at certain plants. Some of our
gas-fired units can use residual fuel oil or distillates instead of gas. Gas is purchased under contracts with suppliers on the spot market and forward markets, including financial
exchanges and under bilateral agreements. The actual fuel quantities required can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather
conditions, and operating requirements. However, we believe that we will be able to obtain adequate quantities of gas to meet our requirements.

Oil

From 2006 through 2008, our requirements for residual fuel oil (No. 6) amounted to less than 0.5 million barrels of
low-sulfur oil per year. Deliveries of residual fuel oil are made from the suppliers' Baltimore Harbor and Philadelphia marine terminals for distribution to the various generating plant
locations. Also, based on normal burn practices, we require approximately 8.0 million to 11.0 million gallons of distillates (No. 2 oil and kerosene) annually, but these
requirements can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. Distillates are purchased
from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices, and for future
delivery, to meet our requirements.

Competition

We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and
differing strategies.

We
face competition in the market for energy, capacity, and ancillary services. In our merchant energy business, we compete with international, national, and regional
full-service energy providers, merchants, and producers to obtain competitively priced supplies from a variety of sources and locations, and to utilize efficient transmission,
transportation, or storage. We principally compete on the basis of price, customer service, reliability, and availability of our products.

With
respect to power generation, we compete in the operation of energy-producing projects, and our competitors in this business are both domestic and international organizations,
including various utilities, industrial companies and independent power producers (including affiliates of utilities, financial investors, and banks), some of which have greater financial resources.

10

---



Table of Contents

States
are considering different types of regulatory initiatives concerning competition in the power and gas industry, which makes a competitive assessment difficult. Many states
continue to support or expand retail competition and industry restructuring. Other states that were considering deregulation have slowed their plans or postponed consideration of deregulation. In
addition, certain previously restructured states are considering re-regulation of their retail markets. While there is significant activity in this area, we believe there is adequate
growth potential in the current deregulated market.

As
the market for commercial, industrial, and governmental energy supply continues to grow, we have experienced increased competition on a regional basis in our retail competitive supply
activities. The increase in retail competition and the impact of wholesale power prices compared to the rates charged by local utilities has, in certain circumstances, reduced the margins that we
realize from our customers. However, we believe that our experience and expertise in
assessing and managing risk and our strong focus on customer service will help us to remain competitive during volatile or otherwise adverse market circumstances.

Merchant Energy Operating Statistics

2008

2007

2006Gross Margin(In millions)Generation

$
1,956

$
1,700

$
1,490Customer Supply


765


889


764Global Commodities


260


654


656Total Gross Margin

$
2,981

$
3,243

$
2,910Generation(In millions)MWH *


50.9


51.6


59.1


Operating statistics do not reflect the elimination of intercompany transactions.

---

11

---



Table of Contents

Baltimore Gas and Electric Company

BGE is an electric transmission and distribution utility company and a gas distribution utility company with a service territory that
covers the City of Baltimore and all or part of ten counties in central Maryland. BGE is regulated by the Maryland PSC and Federal Energy Regulatory Commission (FERC) with respect to rates and other
aspects of its business.

BGE's
electric service territory includes an area of approximately 2,300 square miles. There are no municipal or cooperative wholesale customers within BGE's service territory. BGE's gas
service territory includes an area of approximately 800 square miles.

BGE's
electric and gas revenues come from many customersresidential, commercial, and industrial.

Electric Business

Electric Competition

Deregulation

Maryland has implemented electric customer choice and competition among electric suppliers. As a result, all customers can choose their electric
energy supplier. While BGE does not sell electricity to all customers in its service territory, BGE continues to deliver electricity to all customers and provides meter reading, billing, emergency
response, and regular maintenance.

Standard Offer Service

BGE is obligated to provide market-based standard offer service (SOS) to all of its electric customers who elect not to select a competitive energy
supplier. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost
component. As discussed inItem 7. Management's Discussion and AnalysisRegulated Electric Businesssection, BGE resumed collection
of the shareholder return portion of the residential SOS administrative charge, which had been eliminated under Maryland Senate Bill 1, from June 1, 2008 through May 31, 2010 without
having to rebate it to all residential electric customers. BGE will cease collecting the residential shareholder return component again from June 1, 2010 through December 31, 2016.

Bidding
to supply BGE's SOS occurs from time to time through a competitive bidding process approved by the Maryland PSC. Successful bidders, which may include subsidiaries of
Constellation Energy, execute contracts with BGE for varying terms.

Commercial and Industrial Customers

BGE is obligated to provide several variations of SOS to commercial and industrial customers depending on customer load.

For
those commercial and industrial customers for which SOS originally had been scheduled to expire at the end of May 2007, BGE must continue to provide SOS indefinitely on substantially
the same terms as under the then existing service, except that wholesale bidding for service to some customers will be conducted more frequently.

BGE's
obligation to provide SOS to its largest commercial and industrial customers expired in 2005. However, BGE continues to provide an hourly priced SOS to those customers.

Residential Customers

As a result of the November 1999 Maryland PSC order regarding the deregulation of electric generation in Maryland, BGE's residential electric
base rates were frozen until July 2006. However, Maryland Senate Bill 1, enacted in June 2006, delayed full market rates for some residential customers until June 2007, with the remainder of
residential customers going to full market rates in January 2008. Pursuant to a settlement agreement entered into with the State of Maryland, the Maryland PSC, and certain Maryland officials in March
2008, BGE provided residential electric customers approximately $189 million in the form of a one-time $170 per customer rate credit. We discuss the Maryland settlement agreement in
more detail inNote 2 to Consolidated Financial Statementsand the market risk of our regulated electric business in more detail in Item 7. Management' Discussion and
AnalysisRisk Managementsection.

Electric Load Management

BGE has implemented various programs for use when system-operating conditions or market economics indicate that a reduction in load would be
beneficial. These programs include:



These
programs generally take effect on summer days when demand and/or wholesale prices are relatively high and had the effect of reducing BGE's system peak load by 236 MW during the
summer period in 2008.

BGE
is developing other programs designed to help manage its peak demand, improve system reliability and improve service to customers by giving customers greater control over their
energy use.

BGE
has concluded an advanced metering pilot program and is utilizing the results to develop a strategy for full deployment of the advanced metering program. BGE is also continuing a
pilot program to evaluate pricing options designed to incentivize customers to

12

---



Table of Contents

decrease
energy use during peak demand periods. Additionally, in 2007, BGE initiated a limited conservation program that provides incentives to customers to use energy efficient products and to take
other actions to conserve energy. The Maryland PSC recently approved a full portfolio of conservation programs for implementation in 2009 as well as a customer surcharge to recover the associated
costs. We also discuss the demand response initiatives inItem 7. Management's Discussion and AnalysisRegulationMarylandMaryland
PSCsection.

Transmission and Distribution Facilities

BGE maintains approximately 250 substations and approximately 1,300 circuit miles of transmission lines throughout central Maryland. BGE also
maintains approximately 24,500 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of PJM Interconnection (PJM). Under the
PJM Tariff and various agreements, BGE and other market participants can use regional transmission facilities for energy, capacity, and ancillary services transactions, including emergency assistance.

We
discuss various FERC initiatives relating to wholesale electric markets in more detail inItem 7. Management's Discussion and
AnalysisFederal Regulationsection.

Electric Operating Statistics

2008

2007

2006Revenues(In millions)Residential

$
1,695.9

$
1,514.9

$
1,092.1CommercialExcluding Delivery Service Only


604.0


577.4


733.4Delivery Service Only


222.8


217.0


149.4IndustrialExcluding Delivery Service Only


31.3


31.6


46.8Delivery Service Only


27.1


27.8


26.2System Sales and Deliveries


2,581.1


2,368.7


2,047.9Other (A)


98.6


87.0


68.0Total

$
2,679.7

$
2,455.7

$
2,115.9Distribution Volumes(In thousands)MWHResidential


13,023


13,365


12,886CommercialExcluding Delivery Service Only


3,957


4,364


6,325Delivery Service Only


11,739


11,921


9,392IndustrialExcluding Delivery Service Only


242


287


467Delivery Service Only


3,002


3,175


2,988Total


31,963


33,112


32,058Customers(In thousands)Residential


1,108.5


1,103.1


1,093.3Commercial


117.6


116.7


115.5Industrial


5.3


5.5


5.2Total


1,231.4


1,225.3


1,214.0


Operating statistics do not reflect the elimination of intercompany transactions.
"Delivery service only" refers to BGE's delivery of electricity that was purchased by the customer from an alternate supplier.

13

---





Table of Contents

Gas Business

The wholesale price of natural gas as a commodity is not subject to regulation. All BGE gas customers have the option to purchase gas
from alternative suppliers, including subsidiaries of Constellation Energy. BGE continues to deliver gas to all customers within its service territory. This delivery service is regulated by the
Maryland PSC.

BGE
also provides customers with meter reading, billing, emergency response, regular maintenance, and balancing services.

Approximately
50% of the gas delivered on BGE's distribution system is for customers that purchase gas from alternative suppliers. These customers are charged fees to recover the costs
BGE incurs to deliver the customers' gas through our distribution system.

A
market-based rates incentive mechanism applies to customers that buy their gas from BGE. Under this mechanism, BGE's actual cost of gas is compared to a market index (a measure of the
market price of gas in a given period). The difference between BGE's actual cost and the market index is shared equally between shareholders and customers. BGE must secure fixed-price contracts for at
least 10%, but not more than 20%, of forecasted system supply requirements
for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.

BGE
meets its natural gas load requirements through firm pipeline transportation and storage entitlements.

BGE's
current pipeline firm transportation entitlements to serve its firm loads are 338,053 dekatherms (DTH) per day.

BGE's
current maximum storage entitlements are 254,697 DTH per day. To supplement its gas supply at times of heavy winter demands and to be available in temporary emergencies affecting
gas supply, BGE has:



BGE
has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas during the summer months
for operations of its liquefied natural gas facility during peak winter periods.

BGE
historically has been able to arrange short-term contracts or exchange agreements with other gas companies in the event of short-term disruptions to gas
supplies or to meet additional demand.

BGE
also participates in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales
are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between shareholders and customers. BGE makes these sales as part of a
program to balance its supply of, and cost of, natural gas.

14

---



Table of Contents

Gas Operating Statistics

2008

2007

2006Revenues(In millions)ResidentialExcluding Delivery Service Only

$
567.8

$
552.0

$
490.2Delivery Service Only


19.0


19.0


20.6CommercialExcluding Delivery Service Only


161.8


154.1


148.9Delivery Service Only


46.4


41.2


35.9IndustrialExcluding Delivery Service Only


8.1


7.8


7.5Delivery Service Only


14.5


22.1


19.3System Sales and Deliveries


817.6


796.2


722.4Off-System Sales


197.7


157.4


168.6Other


8.7


9.2


8.5Total

$
1,024.0

$
962.8

$
899.5Distribution Volumes(In thousands)DTHResidentialExcluding Delivery Service Only


37,675


39,199


33,019Delivery Service Only


4,119


4,310


3,948CommercialExcluding Delivery Service Only


12,205


12,464


11,683Delivery Service Only


29,289


30,367


25,695IndustrialExcluding Delivery Service Only


650


658


604Delivery Service Only


18,432


17,897


20,325System Sales and Deliveries


102,370


104,895


95,274Off-System Sales


18,782


19,963


19,738Total


121,152


124,858


115,012Customers(In thousands)Residential


605.0


602.3


597.1Commercial


42.8


42.7


42.3Industrial


1.1


1.2


1.2Total


648.9


646.2


640.6


Operating statistics do not reflect the elimination of intercompany transactions."Delivery service only" refers to BGE's delivery of gas that was purchased by the customer from an alternate
supplier.

Franchises

BGE has nonexclusive electric and gas franchises to use streets and other highways that are adequate and sufficient to permit it to
engage in its present business. Conditions of the franchises are satisfactory.

Other Nonregulated Businesses

UniStar Nuclear

In 2005, we formed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc., (AREVA) to introduce the
advanced design Evolutionary Power Reactor to the U.S. market. Upon conversion to U.S. electrical standards, the technology will be known as the U.S. EPR.

In
August 2007, we formed a joint venture, UniStar Nuclear Energy, LLC (UNE) with EDF. We have a 50% ownership interest in this joint venture to develop, own, and operate new
nuclear projects in the United States and Canada. EDF initially invested $350 million of cash in UNE, and we contributed our interest in UniStar and other UniStar-related assets, which had a
book value of $49 million, and the right to develop new nuclear projects at our existing nuclear plant locations. In the event that the joint venture is terminated, the remaining equity of UNE,
after certain expenses, will be divided equally between Constellation Energy and EDF pursuant to the joint venture agreement.

In
2008, EDF contributed an additional $175 million to UNE based upon reaching certain licensing milestones. EDF will contribute up to an additional $100 million to UNE,
for a total of $625 million, upon reaching additional licensing

15

---



Table of Contents

milestones
after which future funding will be made on a pro rata basis. In 2008, we contributed additional assets which had a book value of $2 million.

In
connection with this joint venture, in 2007 we entered into an investor agreement with EDF under which EDF is limited to owning no more than 9.9% of our outstanding common stock until
July 2012 and is required to vote any shares of our common stock owned by it in the manner recommended by our Board of Directors and not take any actions that seek control of Constellation Energy
until July 2012. In connection with the execution of the Investment Agreement in December 2008, the investor agreement was amended to enable EDF, in connection with certain extraordinary events, such
as a change in control transaction, to acquire shares of our common stock above the 9.9% limitation and to vote its shares at its discretion. The amended investor agreement also provides that
following EDF's acquisition of 49.99% of our nuclear generation and operation business, EDF will have the right to appoint one director to our Board of Directors. As of December 31, 2008, EDF
owned approximately 8.5% of our outstanding common stock.

Energy Projects and Services

We offer energy projects and services to large commercial, industrial and governmental customers. These energy products and services
include:



Home Products and Gas Retail Marketing

We offer services to customers in Maryland including:



Consolidated Capital Requirements

Our total capital requirements for 2008 were $2.2 billion. Of this amount, $1.7 billion was used in our nonregulated
businesses and $0.5 billion was used in our regulated business. We estimate our total capital requirements will be $1.7 billion in 2009.

We
continuously review and change our capital expenditure programs, so actual expenditures may vary from the estimate above. We discuss our capital requirements further in Item 7. Management's Discussion and
AnalysisCapital Resourcessection.

Environmental Matters

The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of
electric generating and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of development to the
ongoing operation of existing or new electric generating and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and
water, protection of natural and cultural resources, and chemical and waste handling and disposal.

We
continuously monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, we assess
their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our capital expenditures were approximately $750 million
during the five-year period 2004-2008 to comply with existing environmental standards and regulations. Our estimated environmental capital requirements for the next three years
are approximately $330 million in 2009, $50 million in 2010, and $25 million in 2011.

Air Quality

Federal

The Clean Air Act created the basic framework for the federal and state regulation of air pollution.

National Ambient Air Quality Standards (NAAQS)

The NAAQS are federal air quality standards authorized under the Clean Air Act that establish maximum ambient air concentrations for the following
specific pollutants: ozone (smog), carbon monoxide, lead, particulates, SO2, and nitrogen dioxides.

In
order for states to achieve compliance with the NAAQS, the Environmental Protection Agency (EPA) adopted the Clean Air Interstate Rule (CAIR) in March 2005 to further reduce ozone and
fine particulate pollution by addressing the interstate transport of SO2 and NOx emissions from fossil fuel-fired generating facilities located primarily in the
Eastern United States.

In
December 2008, the United States Court of Appeals for the District of Columbia Circuit reversed its July 2008 decision to effectively repeal CAIR and remanded the issue to the EPA for
reconsideration. As a result, the requirements of CAIR remain in effect until the EPA takes further action. We cannot predict what additional judicial, legislative or regulatory actions will be taken
in response to the court's decision or the EPA's reconsideration of CAIR or whether such actions may affect our financial results. We do not believe that the repeal of CAIR would result in a material
change to our emissions reduction plan in Maryland as the emissions reduction requirements of Maryland's HAA and Clean

16

---



Table of Contents

Power
Rule (CPR) are more stringent and apply sooner than those under CAIR. However, future changes in CAIR could affect the market prices of SO2 and NOx emission allowances,
which could in turn affect our financial results. We discuss the impact that these rulings had on our 2008 results inItem 7. Management's Discussion and
AnalysisMerchant Energy Businesssection. We discuss these rulings in more detail in theNote 12 to Consolidated Financial
Statements.

In
March 2008, the EPA adopted a stricter NAAQS for ozone. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until
the states in which our generating facilities are located adopt plans to meet the new standards.

In
December 2006, the United States Court of Appeals for the District of Columbia Circuit ruled that a requirement to impose fees on emissions sources based on the previous ozone
standard (Section 185 fees), which had been rescinded by the EPA in May 2005, remained applicable retroactive to November 2005 and remanded the issue to the EPA for reconsideration. A petition
to the United States Supreme Court to hear an appeal was denied in January 2008. The EPA has announced that it intends to propose regulations to address how Section 185 fees will be handled. In
addition, the exact method of computing these fees has not been established and will depend in part on state implementation regulations that have not been proposed. Consequently, we are unable to
estimate the ultimate financial impact of this matter in light of the uncertainty surrounding the anticipated EPA and state rulemakings. However, the final resolution of this matter, and any fees that
are ultimately assessed could have a material impact on our financial results.

In
September 2006, the EPA adopted a stricter NAAQS for particulate matter. We are unable to determine the impact that complying with the stricter NAAQS for particulate matter will have
on our financial results until the states in which our generating facilities are located adopt plans to meet the new standard.

Hazardous Air Emissions

In March 2005, the EPA finalized the CAMR to reduce the emissions of mercury from coal-fired facilities through a market-based cap and
trade program. CAMR was to affect all coal or waste coal fired boilers at our generating facilities. However, in February 2008, the United States Court of Appeals for the District of Columbia Circuit
struck down CAMR. In response to this decision, the EPA recently announced that it intends to develop new mercury emission standards under the CAA. Any new standards that require the installation of
additional emissions control technology beyond what is required under Maryland's Healthy Air Act and Clean Power Rule, which are discussed below, may require us to incur additional costs, which could
have a material effect on our financial results.

New Source Review

In connection with its enforcement of the CAA's new source review requirements, in 2000, the EPA requested information relating to modifications made
to our Brandon Shores, Crane, and Wagner plants located in Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning
plants in which we have an ownership interest. We responded to the EPA in 2001, and as of the date of this report the EPA has taken no further action.

As
discussed inNote 12 to Consolidated Financial Statements, in January 2009, the EPA issued a Notice of Violation to one of our
subsidiaries alleging that the Keystone plant located in Pennsylvania, of which we own a 21% interest, performed various capital projects without complying with the new source review requirements.

Based
on the level of emissions control that the EPA and states are seeking in new source review enforcement actions, we believe that material additional costs and penalties could be
incurred, and planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities.

State

Maryland has adopted the HAA and the CPR, which establish annual SO2, NOx, and mercury emission caps for specific
coal-fired units in Maryland, including units located at three of our facilities. The requirements of the HAA and the CPR for SO2, NOx, and mercury emissions are
more stringent and apply sooner than those required under CAIR. In addition, Pennsylvania had adopted regulations requiring coal-fired generating facilities located in Pennsylvania to
reduce mercury emissions. As we discuss in theCoalsection, a Pennsylvania court held that those regulations were invalid in January 2009.

Several
other states in the northeastern U.S. continue to consider more stringent and earlier SO2, NOx, and mercury emissions reductions than those required under
CAIR or CAMR.

Maryland
also is in the process of considering changes to its current opacity regulations consistent with its commitment to resolve long-standing industry concerns about the
regulations' continuous compliance requirements. However, we are not yet able to determine the final form these revised regulations will take or the impact such revised regulations could have on our
business or financial results.

17

---



Table of Contents

Capital Expenditure EstimatesAir Quality

We expect to incur additional environmental capital spending as a result of complying with the air quality laws and regulations discussed above. To
comply with HAA and CPR, we will install additional air emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned
coal-fired facilities in Pennsylvania to meet air quality standards. We include in our estimated environmental capital requirements capital spending for these air quality projects, which
we expect will be approximately $295 million in 2009, $40 million in 2010, $15 million in 2011 and $30 million from 2012-2013.

Our
estimates are subject to significant uncertainties including the timing of any additional federal and/or state regulations or legislation, such as any regulations adopted by the EPA
in response to the court decision striking down CAMR, the implementation timetables for such regulation or legislation, and the specific amount of emissions reductions that will be required at our
facilities. As a result, we cannot predict our capital spending or the scope or timing of these projects with certainty, and the actual expenditures, scope, and timing could differ significantly from
our estimates.

We
believe that the additional air emission control equipment we plan to install will meet the emission reduction requirements under HAA and CPR. If additional emission reductions still
are required, we will assess our various compliance alternatives and their related costs, and although we cannot yet estimate the additional costs we may incur, such costs could be material.

Global Climate Change

Although uncertainty remains as to the nature and timing of greenhouse gas emissions regulation, there is an increasing likelihood that such
regulation will occur at the federal and/or state level. In the event that greenhouse gas emissions reduction legislation or regulations are enacted, we will assess our various compliance
alternatives, which may include installation of additional environmental controls, modification of operating schedules, or the closure of one or more of our coal-fired generating
facilities. Any compliance costs we incur could have a material impact on our financial results.

However,
to the extent greenhouse gas emissions are regulated through a federal, mandatory cap and trade greenhouse gas emissions program, we believe our business could also benefit. Our
generation fleet currently has a carbon dioxide (CO2) emission rate lower than the industry average with more than 60% of the fleet's output coming from low CO2 emitting
nuclear and hydroelectric plants. Our global commodities operation has experience trading in the markets for emissions allowances and renewable energy credits.

In
accordance with HAA requirements, Maryland became a full participant in the Northeast Regional Greenhouse Gas Initiative (RGGI) in April 2007. Under RGGI, the Maryland Department of
the Environment auctions 100% of CO2 allowances associated with Maryland's power plants, which include plants owned by us. Auctions occurred in September and December 2008. Although we did
not incur material costs in these auctions, we could incur material costs in the future to purchase CO2 allowances necessary to offset emissions from our plants.

In
addition, California has adopted regulations requiring our generating facilities in California to submit greenhouse gas emissions data to the state, which the state intends to use to
develop a plan to reduce greenhouse gas emissions.

We
continue to evaluate the potential impact of the HAA and California CO2 emissions requirements and RGGI participation on our financial results, however, our compliance
costs could be material.

Water Quality

The Clean Water Act established the basic framework for federal and state regulation of water pollution control and requires facilities that
discharge waste or storm water into the waters of the United States to obtain permits.

Water Intake Regulations

The Clean Water Act requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts.
In July 2004, the EPA published final rules under the Clean Water Act for existing facilities that establish performance standards for meeting the best technology available for minimizing adverse
environmental impacts. We currently have seven facilities affected by the regulation. In January 2007, the United States Court of Appeals for the Second Circuit ruled that the EPA's rule did not
properly implement the Clean Water Act requirements in a number of areas and remanded the rule to the EPA for reconsideration.

In
response to this ruling, in July 2007, the EPA suspended the second phase of the regulations pending further rulemaking and directed the permitting authorities to establish controls
for cooling water intake structures that reflect the best technology available for minimizing adverse environmental impacts. In December 2008, the United States Supreme Court heard an appeal of the
Second Circuit's decision relating to the application of cost-benefit analysis to best technology available decisions and a decision is expected in 2009.

In
addition, the EPA is expected to propose new regulations, but the timing of those regulations is uncertain. We will evaluate our compliance options in light of the Supreme Court and
Second Circuit

18

---



Table of Contents

decisions,
the EPA's July 2007 order and any subsequent EPA proposals. At this time, we cannot estimate our compliance costs, but they could be material.

Hazardous and Solid Waste

We discuss proceedings relating to compliance with the Comprehensive Environmental Response, Compensation and Liability Act in Note 12 to Consolidated Financial Statements.

Our
coal-fired generating facilities produce approximately two and a half million tons of combustion by-products ("ash") each year. The EPA announced in 2007 its
intention to develop national standards to regulate this material as a non-hazardous waste, and has been developing or considering regulations governing the placement of ash in landfills,
surface impoundments, sand/gravel surface mines and coal mines. In addition, the Maryland Department of the Environment finalized regulations governing the disposal, storage, use and placement of ash
in December 2008. Federal regulation has the potential to result in additional requirements. Depending on the scope of any final federal requirements, our compliance costs could be material.

As
a result of these regulatory proposals and our current ash generation projections, we are exploring our options for the management of ash, including construction of an ash placement
facility. Over the next five years, we estimate that our capital expenditures for this project will be approximately $60 million. Our estimates are subject to significant uncertainties,
including the timing of any regulatory change, its implementation timetable, and the scope of the final requirements. As a result, we cannot predict our capital spending or the scope and timing of
this project with certainty, and the actual expenditures, scope and timing could differ significantly from our estimates.

Employees

In December 2008, we announced a global workforce reduction of approximately 8%. We completed a portion of this reduction in 2008
with the remainder expected to occur in 2009 in connection with our efforts to sell our upstream gas properties and finalize the sale of a majority of our international commodities operation and our
gas trading operation.

Constellation
Energy and its subsidiaries had approximately 10,200 employees at December 31, 2008. At the Nine Mile Point facility, approximately 500 employees are represented by
the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in June 2011. We believe that our relationship with this union is satisfactory, but there can
be no assurances that this will continue to be the case.

Available Information

Constellation Energy maintains a website at constellation.com where copies of our annual reports on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments may be obtained free of charge. These reports are posted on our website the same
day they are filed with the SEC. The SEC maintains a website (sec.gov), where copies of our filings may be obtained free of charge. The website address for BGE is bge.com. These website addresses are
inactive textual references, and the contents of these websites are not part of this Form 10-K.

In
addition, the website for Constellation Energy includes copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate Compliance Program, Insider Trading
Policy, Policy and Procedures with respect to Related Person Transactions, Information Disclosure Policy, and the charters of the Audit, Compensation and Nominating and Corporate Governance Committees
of the Board of Directors. Copies of each of these documents may be printed from our website or may be obtained from Constellation Energy upon written request to the Corporate Secretary.

The
Principles of Business Integrity is a code of ethics that applies to all of our directors, officers, and employees, including the chief executive officer, chief financial officer,
and chief accounting officer. We will post any amendments to, or waivers from, the Principles of Business Integrity applicable to our chief executive officer, chief financial officer, or chief
accounting officer on our website.

19

---





Table of Contents

Item 1A. Risk Factors

You should consider carefully the following risks, along with the other information contained in this
Form 10-K. The risks and uncertainties described below are not the only ones that may affect us. Additional risks and uncertainties also may adversely affect our business and
operations including those discussed in Item 7. Management's Discussion and Analysis. If any of the following events actually occur, our business and financial results could be materially
adversely affected.

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are affected by local, national, and worldwide economic conditions. The consequences of a prolonged recession may
include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy
consumption, an increase in customers' inability to pay their accounts, and lower commodity prices. These impacts may adversely affect our financial results and future growth.

Instability
in the financial markets, as a result of recession or otherwise, may affect the cost of capital and our ability to raise capital. We rely on the capital markets, as well as
the banking and commercial paper markets to the extent available, to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations.
We also use letters of credit issued under our credit facilities to support our operations. Disruptions in the capital and credit markets as a result of uncertainty, reduced alternatives, or failures
of significant financial institutions could adversely affect our access to liquidity needed for our businesses, including our ability to secure credit facilities and refinance debt that comes due, and
our ability to complete other alternatives we are exploring. In addition, such disruptions could adversely affect our ability to draw on our credit facilities. Our access to funds under those credit
facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to us if they
experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from borrowers within a short period of time. The disruptions in capital and credit markets
may also result in higher interest rates on publicly issued debt securities and increased costs associated with commercial paper borrowing and under bank credit facilities.

Any
disruptions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be
arranged. Such measures could include deferring capital expenditures, further changing our strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or
other discretionary uses of cash. The inability to obtain the liquidity needed to meet our business requirements, or to obtain such liquidity on terms that are favorable to us, would have a material
adverse effect on our business, results of operations and financial condition. If entities with which we do business are unable to raise capital or access the credit markets, they may be unable to
perform their obligations or make payments under agreements we have with them. Defaults by these entities may have an adverse effect on our financial results.

We may be unable to execute our strategies to improve liquidity and reduce invested capital.

In an effort to improve our liquidity and reduce our business risk, we are undertaking a number of strategic initiatives to reduce
capital spending and ongoing expenses, scale down the expected variability in long-term earnings and short-term collateral usage, and limit our exposure to business activities
that require contingent capital support. In connection with these efforts, we have entered into agreements to sell the majority of our international commodities operation and our gas trading operation
and we have signed a letter of intent to enter into a gas supply arrangement to support our retail gas activities. While we have entered into these agreements, they remain subject to regulatory
approval and other standard closing conditions and we cannot provide any assurance that these sales or other sales will be completed.

In
addition, if we cannot execute on our strategic initiatives successfully, including completing the sales of our international commodities operation and our gas trading operation, our
liquidity will be adversely affected, which would have a material adverse effect on our business, results of operations, and financial condition.

A downgrade in our credit ratings could negatively affect our ability to access capital and/or operate our wholesale and retail competitive supply businesses.

We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. If any
of our credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including in the commercial paper markets, if available, could be
hindered, and our borrowing costs would increase. Additionally, the business prospects of our wholesale and retail competitive supply businesses, which in many cases rely on the creditworthiness of
Constellation Energy, would be negatively impacted. In this regard, we have certain agreements that contain provisions that would require us to post additional collateral upon a credit rating
downgrade. Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that exceeds our available liquidity. Also, a credit
rating downgrade would

20

---



Table of Contents

require
us to grant a lien on certain of our generation assets and pledge our ownership interest in our nuclear generation business to the lenders under our credit facilities following the closing or
termination of our investment agreement with EDF. Some of the factors that affect credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, and political,
legislative, and regulatory events. Also, failure to complete our sales of the majority of our international commodities operation and our gas trading operation could result in a credit rating
downgrade.

Changes in the prices of commodities and initial margin requirements impact our liquidity requirements.

As a result of the nature of our business, we are exposed to the impact of market fluctuations in the price and transportation costs
of electricity, natural gas, coal, uranium, and other commodities. We seek to mitigate the effect of these fluctuations through various hedging strategies, which may require the posting of collateral
by both us and our counterparties. Changes in the prices of commodities and initial margin requirements for exchange-traded contracts can affect the amount of collateral that must be posted, depending
on the particular position we hold. There are certain asymmetries relating to the use of collateral that create liquidity requirements for our merchant energy business. These asymmetries arise as a
result of our actions to be economically hedged as well as market conditions or conventions for conducting business that result in some transactions being collateralized while others are not. As a
result, significant changes in the prices of commodities and margin requirements for exchange-traded contracts could require us to post additional collateral from time to time without our
counterparties having to post collateral to us, which could adversely affect our overall liquidity and ability to finance our operations, which, in turn, could adversely affect our credit ratings.

Our merchant energy business may incur substantial costs and liabilities and be exposed to price volatility and counterparty performance risk as a result of its
participation in the wholesale energy markets.

We purchase and sell power and fuel in markets exposed to significant risks, including price volatility for electricity and fuel and
the credit risks of counterparties with which we enter into contracts.

We
use various hedging strategies in an effort to mitigate many of these risks. However, hedging transactions do not guard against all risks and are not always effective, as they are
based upon predictions about future market conditions. The inability or failure to effectively hedge assets or fuel or power positions against changes in commodity prices, interest rates, counterparty
credit risk or other risk measures could significantly impair future financial results.

Exposure to electricity price volatility.We buy and sell electricity in both the wholesale bilateral markets and spot
markets, which expose us to the risks of rising and falling prices in those markets, and our cash flows may vary accordingly. At any given time, the wholesale spot market price of electricity for each
hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. This is highly dependent on the regional generation market. In many cases, the next
unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily coal, natural gas and oil. Consequently, the open market wholesale price of electricity may
reflect the cost of coal, natural gas or oil plus the cost to convert the fuel to electricity and an appropriate return on capital. Therefore, changes in the supply and cost of coal, natural gas and
oil may impact the open market wholesale price of electricity.

A
portion of our power generation facilities operates wholly or partially without long-term power purchase agreements. As a result, power from these facilities is sold on the
spot market or on a short-term contractual basis, which if not fully hedged may affect the volatility of our financial results.

Exposure to fuel cost volatility.Currently, our power generation facilities purchase a portion of their fuel through
short-term contracts or on the spot market. Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs.
As a result, fuel price changes may adversely affect our financial results.

Exposure to counterparty performance.Our merchant energy business enters into transactions with numerous third parties
(commonly referred to as "counterparties"). In these arrangements, we are exposed to the credit risks of our counterparties and the risk that one or more counterparties may fail to perform under their
obligations to make payments or deliver fuel or power. In addition, we enter into various wholesale transactions through Independent System Operators (ISOs). These ISOs are exposed to counterparty
credit risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These risks are exacerbated during periods of
commodity price fluctuations. If a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of derivative contracts
recorded at fair value, the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts. Defaults by suppliers
and other counterparties may adversely affect our financial results.

21

---



Table of Contents

Reduced liquidity in the markets in which we operate could impair our ability to appropriately manage the risks of our operations.

We are an active participant in energy markets through our competitive energy businesses. The liquidity of regional energy markets is
an important factor in our ability to manage risks in these operations. Over the past several years, other market participants in the merchant energy business have ended or significantly reduced their
activities as a result of several factors, including government investigations, changes in market design, and deteriorating credit quality. As a result, several regional energy markets experienced a
significant decline in liquidity, which, in turn, has impacted our ability to enter into certain types of transactions to manage our risks for settlement periods beyond 18 to 24 months. Liquidity in
the energy markets can be adversely affected by various factors, including price volatility and the
availability of credit. As a result, future reductions in liquidity may restrict our ability to manage our risks and this could impact our financial results.

We often rely on single suppliers and at times on single customers, exposing us to significant financial risks if either should fail to perform their obligations.

We often rely on a single supplier for the provision of fuel, water, and other services required for operation of a facility, and at
times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that provide the support
for any project debt used to finance the facility. The failure of any one customer or supplier to fulfill its contractual obligations could negatively impact our financial results. Consequently, our
financial performance depends on the continued performance by customers and suppliers of their obligations under these agreements.

We may not fully hedge our generation assets, customer supply activities, or other market positions against changes in commodity prices, and our hedging procedures may not
work as planned.

To lower our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our
purchase and sale commitments, weather positions, fuel requirements, inventories of natural gas, coal and other commodities, and competitive supply obligations. As part of this strategy, we routinely
utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges.
However, we may not cover the entire exposure of our assets or positions to market price volatility, and the coverage will vary over time. Fluctuating commodity prices may negatively impact our
financial results to the extent we have unhedged positions.

In
addition, risk management tools and metrics such as daily value at risk, economic value at risk, stop loss limits and liquidity guidelines are based on historical price movements. If
price movements significantly or persistently deviate from historical behavior, the limits may not protect us from significant losses.

Our
risk management policies and procedures may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that risk management
decisions may have on our financial results.

The use of derivative contracts in the normal course of business could result in financial losses that negatively impact our financial results.

We use derivative instruments such as swaps, options, futures and forwards to manage our commodity and financial market risks and to
engage in trading activities. We could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.

In
the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative instruments involves management's judgment or use of
estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Additionally,
the settlement of these derivative instruments could reflect a realized value that differs from our estimates of fair value.

Poor market performance will affect our benefit plan and nuclear decommissioning trust asset values, which may adversely affect our liquidity and financial results.

At December 31, 2008, our qualified pension obligations were approximately $835 million greater than the fair value of
our plan assets. The Pension Protection Act requires that we fully fund our obligations by 2015. The performance of the capital markets will affect the value of the assets that are held in trust to
satisfy our future obligations under our qualified pension plans. A decline in the market value of those assets or the failure of those assets to earn an adequate return may increase our funding
requirements for these obligations, which may adversely affect our liquidity and financial results.

We
are required to maintain funded trusts to satisfy our future obligations to decommission our nuclear power plants. A decline in the market value of those assets due to poor investment
performance or other factors may increase our funding requirements for these obligations, which may have an adverse effect on our liquidity and financial results.

22

---



Table of Contents

The operation of power generation facilities, including nuclear facilities, involves significant risks that could adversely affect our financial results.

We own and operate a number of power generation facilities. The operation of power generation facilities involves many risks,
including start-up risks, breakdown or failure of equipment, transmission lines, substations or pipelines, use of new technology, the dependence on a specific fuel source, including the
transportation of fuel, or the impact of unusual or adverse weather conditions (including natural disasters such as hurricanes) or environmental compliance, as well as the risk of performance below
expected or contracted levels of output or efficiency. This could result in lost revenues and/or increased expenses. Insurance, warranties, or performance guarantees may not cover any or all of the
lost revenues or increased expenses, including the cost of replacement power. A portion of our generation facilities were constructed many years ago. Older generating equipment may require significant
capital expenditures to keep it operating at peak efficiency. This equipment is also likely to require periodic upgrading and improvement. Breakdown or failure of one of our operating facilities may
prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of the agreement or incurring a liability for liquidated damages.

Our generation business may incur substantial costs and liabilities due to its ownership and operation of nuclear generating facilities.

We own and operate nuclear power plants. Ownership and operation of these plants exposes us to risks in addition to those that result
from owning and operating non-nuclear power generation facilities. These risks include normal operating risks for a nuclear facility and the risks of a nuclear accident.

Nuclear Operating Risks.The ownership and operation of nuclear generating facilities involve routine operating risks,
including:



Nuclear Accident Risks.In the event of a nuclear accident, the cost of property damage and other expenses incurred may
exceed our insurance coverage available from both private sources and an industry retrospective payment plan. In addition, in the event of an accident at one of our or another participating insured
party's nuclear plants, we could be assessed retrospective insurance premiums (because all nuclear plant operators contribute to a nationwide catastrophic insurance fund). Uninsured losses or the
payment of retrospective insurance premiums could each have a material adverse effect on our financial results.

Our generation investment plans may not achieve the desired financial results.

We may expand our generation capacity over the next several years through increasing the generating power of existing plants, the
renovation of retired plants owned by us, and the construction or acquisition of new plants. The renovation, development, construction, and acquisition of additional generation capacity involves
numerous risks. Any planned power uprates, construction, or renovation could result in cost overruns, lower than expected plant efficiency, and higher operating and other costs. With respect to the
renovation of retired plants or the construction of new plants, we may incur significant sums for preliminary engineering, permitting, legal, and other expenses before it can be established whether a
project is feasible, economically attractive, or capable of being financed.

If
we were unable to complete the construction or renovation of a plant, we may not be able to recover our investment in the project. Furthermore, we may be unable to run any new,
acquired or renovated plants as efficiently as projected, which could result in higher-than-projected operating and other costs that adversely affect our financial results.

We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations and may expose us to environmental
liabilities.

We are subject to extensive federal, state, and local environmental statutes, rules, and regulations relating to air quality, water
quality, waste management, wildlife protection, the management of natural resources, and the protection of human health and safety that could, among other things, require additional pollution control
equipment, limit the use of certain fuels, restrict the output of certain facilities, or otherwise increase costs. Significant capital expenditures, operating and other costs are associated with
compliance with environmental requirements, and these expenditures and costs could become even more significant in the future as a result of regulatory changes.

For
example, there is increasing likelihood that additional regulation of greenhouse gas emissions will

23

---



Table of Contents

occur
at the federal, regional, and/or state level, which could increase our compliance and operating costs.

We
are subject to liability under environmental laws for the costs of remediating environmental contamination. Remediation activities include the cleanup of current facilities and former
properties, including manufactured gas plant operations and offsite waste disposal facilities. The remediation costs could be significantly higher than the liabilities recorded by us. Also, our
subsidiaries are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future.

We
are subject to legal proceedings by individuals alleging injury from exposure to hazardous substances and could incur liabilities that may be material to our financial results.
Additional proceedings could be filed against us in the future.

We
may also be required to assume environmental liabilities in connection with future acquisitions. As a result, we may be liable for significant environmental remediation costs and
other liabilities arising from the operation of acquired facilities, which may adversely affect our financial results.

We, and BGE in particular, are subject to extensive local, state and federal regulation that could affect our operations and costs.

We are subject to regulation by federal and state governmental entities, including the FERC, the NRC, the Maryland PSC and the
utility commissions of other states in which we have operations. In addition, changing governmental policies and regulatory actions can have a significant impact on us. Regulations can affect, for
example, allowed rates of return, requirements for plant operations, recovery of costs, limitations on dividend payments, and the regulation or re-regulation of wholesale and retail competition
(including, but not limited to, retail choice and transmission costs).

BGE's
distribution rates are subject to regulation by the Maryland PSC, and such rates are effective until new rates are approved. If the Maryland PSC does not approve adequate new
rates, BGE might not be able to recover certain costs it incurs or earn an adequate rate of return. In addition, limited categories of costs are recovered through adjustment charges that are
periodically reset to reflect current and projected costs. Inability to recover material costs not included in rates or adjustment clauses, including increases in uncollectible customer accounts that
may result from higher gas and electric costs, could have an adverse effect on our, or BGE's, cash flow and financial position.

Energy
legislation enacted in Maryland in June 2006 and April 2007 mandated that the Maryland PSC review Maryland's deregulated electricity market. Although the settlement agreement
reached with the State of Maryland in March 2008 terminated certain studies relating to the 1999 deregulation settlement, the State of Maryland, including the Maryland legislature, and the Maryland
PSC are still undertaking a review of the Maryland electric industry and market structure to consider various options for providing standard offer service to residential customers, including
re-regulation. We cannot at this time predict the final outcome of this review or how such outcome may affect our, or BGE's financial results, but it could be material.

The
regulatory and legislative process may restrict our ability to grow earnings in certain parts of our business, cause delays in or affect business planning and transactions and
increase our, or BGE's, costs.

We operate in deregulated segments of the electric and gas industries created by federal and state restructuring initiatives. If competitive restructuring of the electric or
gas industries is reversed, discontinued, restricted, or delayed, our business prospects and financial results could be materially adversely affected.

The regulatory environment applicable to the electric and natural gas industries has undergone substantial changes as a result of
restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the electric and natural gas industries and the manner in which their
participants conduct their businesses. We have targeted the competitive segments of the electric and natural gas industries created by these initiatives.

Due
to recent events in the energy markets, energy companies have been under increased scrutiny by state legislatures, regulatory bodies, capital markets, and credit rating agencies.
This increased scrutiny could lead to substantial changes
in laws and regulations affecting us, including modifications to the auction processes in competitive markets and new accounting standards that could change the way we are required to record revenues,
expenses, assets, and liabilities. Recent proposals by the Maryland PSC and certain members of the Maryland legislature, relating to the structure of the electric industry in Maryland and various
options for re-regulation of the industry are examples of how these laws and regulations can change. We cannot predict the future development of regulation or legislation in these markets
or the ultimate effect that this changing regulatory environment will have on our business.

If
competitive restructuring of the electric and natural gas markets is reversed, discontinued, restricted, or delayed, or if the recent Maryland PSC or legislative proposals are
implemented in a manner adverse to us, our business prospects and financial results could be negatively impacted.

Our financial results may be harmed if transportation and transmission availability is limited or unreliable.

We have business operations throughout the United States and internationally. As a result, we depend on transportation and
transmission facilities owned and operated by utilities and other energy companies to deliver the electricity, coal, and natural gas we sell to

24

---



Table of Contents

the
wholesale and retail markets, as well as the natural gas and coal we purchase to supply some of our generating facilities. If transportation or transmission is disrupted or capacity is inadequate,
our ability to sell and deliver products may be hindered. Such disruptions could also hinder our ability to provide electricity, coal, or natural gas to our customers or power plants and may
materially adversely affect our financial results.

Our merchant energy business has contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load
requirements and may result in increased operating costs to our business.

Our merchant energy business has contractual obligations to certain customers to supply full requirements service to such customers
to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of load that our merchant energy business must be prepared to supply to customers may increase our
operating costs. A significant under- or over-estimation of load requirements could result in our merchant energy business not having enough power or having too much power to cover its
load obligation, in which case it would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating
costs and result in the possibility of reduced earnings or incurring losses.

Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.

Our business is affected by weather conditions. Our overall operating results may fluctuate substantially on a seasonal basis, and
the pattern of this fluctuation may change depending on the nature and location of any facility we acquire and the terms of any contract to which we become a party. Weather conditions directly
influence the demand for electricity and natural gas and affect the price of energy commodities.

Generally,
demand for electricity peaks in winter and summer and demand for gas peaks in the winter. Typically, when winters are warmer than expected and summers are cooler than
expected, demand for energy is lower, resulting in less electric and gas consumption than forecasted. Depending on prevailing market prices for electricity and gas, these and other unexpected
conditions may reduce our revenues and results of operations. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and may make period
comparisons less relevant.

Severe
weather can be destructive, causing outages and/or property damage. This could require us to incur additional costs. Catastrophic weather, such as hurricanes, could impact our or
our customers' operating facilities, communication systems and technology. Unfavorable weather conditions may have a material adverse effect on our financial results.

A failure in our operational systems or infrastructure, or those of third parties, may adversely affect our financial results.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. If any of our
financial, accounting, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely
affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition,
dependence upon automated systems may further increase the risk that operational system flaws or employee tampering or manipulation of those systems will result in losses that are difficult to detect.

We
may also be subject to disruptions of our operational systems arising from events that are wholly or partially beyond our control (for example, natural disasters, acts of terrorism,
epidemics, computer viruses and telecommunications outages). Third party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt one or more of
our businesses, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results.

Our ability to successfully identify, complete and integrate acquisitions is subject to significant risks, including the effect of increased competition.

We are likely to encounter significant competition for acquisition opportunities that may become available. In addition, we may be
unable to identify attractive acquisition opportunities at favorable prices, to secure the financing necessary to undertake them, or to successfully and timely complete and integrate them.

War and threats of terrorism and catastrophic events that could result from terrorism may impact our results of operations in unpredictable ways.

We cannot predict the impact that any future terrorist attacks may have on the energy industry in general and on our business in
particular. In addition, any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel
supplies and markets, particularly oil. The possibility alone that infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities would be direct
targets of, or indirect casualties of, an act of terror may affect our operations.

Such
activity may have an adverse effect on the United States economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely
affect our financial results or restrict our future growth. Instability in the

25

---



Table of Contents

financial
markets as a result of terrorism or war may affect our stock price and our ability to raise capital.

We are subject to employee workforce factors that could affect our businesses and financial results.

We are subject to employee workforce factors, including loss or retirement of key executives or other employees, availability of
qualified personnel, collective bargaining agreements with union employees, and work stoppage that could affect our financial results. In particular, our competitive energy businesses are dependent,
in part, on recruiting and retaining personnel with experience in sophisticated energy transactions and the functioning of complex wholesale markets.

Our transaction with EDF is subject to closing conditions, including regulatory approvals, that, if not satisfied or waived by the appropriate party, will result in the
transaction not being completed, which may result in material adverse consequences to our business and operations.

On December 17, 2008, we announced the execution of an investment agreement with EDF relating to the acquisition by EDF of a
49.99% ownership interest in our nuclear generation and operation business. The transaction is subject to closing conditions, including the receipt of consents, orders, approvals, or clearances from
various federal, state and international regulatory agencies, that, if not satisfied, will prevent the transaction from being completed. In addition, if the agreement is terminated by EDF as a result
of our breach of the agreement, the put arrangement between us and EDF that provides us with additional liquidity of up to $2.0 billion would also terminate.

As
part of the regulatory approval process, governmental entities may impose terms and conditions that may not be acceptable to us or EDF, which may give either party the right to
terminate the investment agreement. Also, governmental entities may impose terms and conditions that are unfavorable or add significant additional costs to our
future operations whether the transaction is completed or not. A substantial delay in obtaining required approvals or the imposition of unfavorable terms or conditions in connection with such
approvals could have a material adverse effect on our business or financial results and could also have a negative impact on our credit ratings. In addition, delays or unfavorable terms could lead us
to become involved in litigation with one or more governmental entities or private litigants or may cause us or EDF to terminate the investment agreement.

If the investment agreement with EDF is terminated we will be required to issue senior notes to EDF.

If the investment agreement with EDF is terminated the Series B Preferred Stock acquired by EDF will be redeemed on the later
of the date of termination of the agreement or December 31, 2009 for $1.0 billion in aggregate principal amount of 10% Senior Notes. The 10% Senior Notes to be issued upon redemption of
the Series B Preferred Stock will mature on June 30, 2010. This obligation will reduce the cash available to finance our operations and other business activities and could limit our
flexibility in planning for or reacting to changes in our business. The redemption of the Series B Preferred Stock could also have a negative impact on our credit ratings.

If the investment agreement with EDF is terminated and the 10% Senior Notes are issued by us upon redemption of the Series B Preferred Stock, the 10% Senior Notes
will contain restrictions on the operation of our business.

The 10% Senior Notes to be issued upon redemption of our Series B Preferred Stock contain various covenants that will limit
our ability to engage in specific types of transactions and in operating our business. Constellation Energy and certain of its subsidiaries will be subject to negative covenants that will be
consistent with those included in Constellation Energy's credit facilities, which include limitations on indebtedness; incurring certain liens; engaging in certain fundamental changes; the sale of its
assets; certain types of restricted payments; investments, loans and advances; acquisitions and transactions with affiliates; optional payments and modifications to debt instruments; and the issuance
of capital stock.

The sale of non-nuclear generation plants pursuant to the put arrangement with EDF may have an adverse effect on our financial results.

We have entered into a put arrangement with EDF that, subject to regulatory approval, provides us with additional liquidity of up to
$2.0 billion by allowing us to exercise an option to require EDF to acquire certain specified non-nuclear generation plants at pre-agreed prices. To the extent we
exercise this option, we will no longer own the plants sold to EDF and will not be able to recognize their financial results, which may have an adverse effect on our future financial results.

26

---



Table of Contents

---

Item 2. Properties

Constellation Energy occupies approximately 970,000 square feet of leased and owned office space in North America, which includes its
corporate offices in Baltimore, Maryland. We describe our electric generation properties on the next page. We also have leases for other offices and services located in the Baltimore metropolitan
region, and for various real property and facilities relating to our generation projects.

BGE
owns its principal headquarters building located in downtown Baltimore. BGE also leases approximately 50,000 square feet of office space. In addition, BGE owns propane air and
liquefied natural gas facilities as discussed inItem 1. BusinessGas Businesssection.

BGE
also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City-owned property (principally parks) which
expired in 2004. BGE is in the process of renewing the rights-of-way with Baltimore City for an additional 25 years. The expiration of the
rights-of-way does not affect BGE's ability to use the rights-of-way during the renewal process.

BGE
has electric transmission and electric and gas distribution lines located:



We
believe we have satisfactory title to our power project facilities in accordance with standards generally accepted in the energy industry, subject to exceptions, which in our opinion,
would not have a material adverse effect on the use or value of the facilities.

Our
merchant energy business owns several natural gas producing properties. We also lease office space in Australia, Canada, Indonesia, Japan and the United Kingdom to support our
merchant energy business.

27

---





The following table describes our generating facilities:

Plant

Location

Capacity
(MW)

%
Owned

Capacity Owned
(MW)

Primary
FuelCalvert Cliffs Unit 1 (1)

Calvert Co., MD


873


100.0


873

NuclearCalvert Cliffs Unit 2 (1)

Calvert Co., MD


862


100.0


862

NuclearNine Mile Point Unit 1 (1)

Scriba, NY


620


100.0


620

NuclearNine Mile Point Unit 2 (1)

Scriba, NY


1,138


82.0


933

NuclearR.E. Ginna (1)

Ontario, NY


581


100.0


581

NuclearBrandon Shores

Anne Arundel Co., MD


1,286


100.0


1,286

CoalH. A. Wagner

Anne Arundel Co., MD


995


100.0


995

Coal/Oil/GasC. P. Crane (2)

Baltimore Co., MD


399


100.0


399

Oil/CoalKeystone (2)

Armstrong and Indiana Cos., PA


1,711


21.0


359
(4)
CoalConemaugh (2)

Indiana Co., PA


1,711


10.6


181
(4)
CoalPerryman (2)

Harford Co., MD


355


100.0


355

Oil/GasRiverside

Baltimore Co., MD


228


100.0


228

Oil/GasHandsome Lake (2)

Rockland Twp, PA


268


100.0


268

GasNotch Cliff

Baltimore Co., MD


120


100.0


120

GasWestport

Baltimore City, MD


121


100.0


121

GasGould Street

Baltimore City, MD


97


100.0


97

GasPhiladelphia Road

Baltimore City, MD


64


100.0


64

OilSafe Harbor (2)

Safe Harbor, PA


417


66.7


278

HydroGrande Prairie (2)

Calgary, Alberta, Canada


85


100.00


85

GasWest Valley (2)

West Valley, UT


200


100.00


200

GasPanther Creek (2)

Nesquehoning, PA


80


50.0


40

Waste CoalColver (2)

Colver Township, PA


104


25.0


26

Waste CoalSunnyside (2)

Sunnyside, UT


51


50.0


26

Waste CoalACE (2)

Trona, CA


102


31.1


32

CoalJasmin

Kern Co., CA


35


50.0


18

CoalPOSO

Kern Co., CA


35


50.0


18

CoalMammoth Lakes G-1

Mammoth Lakes, CA


6


50.0


3

GeothermalMammoth Lakes G-2

Mammoth Lakes, CA


13


50.0


7

GeothermalMammoth Lakes G-3

Mammoth Lakes, CA


13


50.0


7

GeothermalRocklin

Placer Co., CA


24


50.0


12

BiomassFresno

Fresno, CA


24


50.0


12

BiomassChinese Station

Jamestown, CA


20


45.0


9

BiomassMalacha

Muck Valley, CA


32


50.0


16

HydroSEGS IV

Kramer Junction, CA


33


12.2


4

SolarSEGS V

Kramer Junction, CA


24


4.2


1

SolarSEGS VI

Kramer Junction, CA


34


8.8


3

SolarTotal Generating Facilities (3)




12,761





9,136


In
February 2008, we acquired the Hillabee Energy Center, a partially completed 774 MW gas-fired combined cycle power generation facility located in Alabama. We plan to complete the
construction of this facility and expect it to be ready for commercial operation in late 2009.

As
of December 31, 2008, we also have a 50% ownership interest in a waste coal processing facility located in Hazelton, Pennsylvania.

28

---



Item 3. Legal Proceedings

We discuss our legal proceedings in Note 12 to Consolidated Financial
Statements.

Item 4. Submission of Matters to Vote of Security Holders

Not applicable.

Executive Officers of the Registrant

Name

Age

Present Office

Other Offices or Positions Held
During Past Five YearsMayo A. Shattuck III

54

Chairman of the Board (since July 2002), President and Chief Executive Officer (since November 2001) of Constellation Energy

Chairman of the Board of Baltimore Gas and Electric CompanyMichael J. Wallace

61

Vice Chairman of Constellation Energy (since March 2008)

President and Chief Executive OfficerConstellation Energy Nuclear Group, LLC and Executive Vice
PresidentConstellation EnergyHenry B. Barron

58

Executive Vice President of Constellation Energy (since April 2008); and President, Chief Executive Officer and Chief Nuclear
Officer (since September 2008) of Constellation Energy Nuclear Group

Group Executive and Chief Nuclear OfficerDuke EnergyThomas F. Brady

59

Executive Vice President of Constellation Energy (since January 2004); and Chairman of the Board of Baltimore Gas and Electric
Company (since April 2007)

NoneJames L. Connaughton

47

Executive Vice President, Corporate Affairs, Public, and Environmental Policy (since February 2009)

Chairman of the White House Council on Environmental Quality and Director of the White House Office of Environmental
PolicyPaul J. Allen

57

Senior Vice President (since January 2004) and Chief Environmental Officer (since June 2007) of Constellation Energy

Vice President, Corporate AffairsConstellation EnergyCharles A. Berardesco

50

Senior Vice President (since October 2008), General Counsel (since October 2008) and Corporate Secretary (since July 2004) of
Constellation Energy

Vice President and Deputy General CounselConstellation Energy; and Associate General CounselConstellation
EnergyBrenda L. Boultwood

44

Senior Vice President and Chief Risk Officer of Constellation Energy (since January 2008)

Global Head of Strategy, Alternative Investment ServicesJ.P. Morgan Chase & CompanyKenneth W. DeFontes, Jr.

58

Senior Vice President of Constellation Energy (since October 2004); and President and Chief Executive Officer of Baltimore Gas
and Electric Company (since October 2004)

Vice President, Electric Transmission and DistributionBaltimore Gas and Electric CompanyKathleen W. Hyle

50

Senior Vice President of Constellation Energy (since September 2005); and Chief Operating Officer of Constellation Energy
Resources (since November 2008)

Senior Vice President, Finance, and Chief Financial OfficerConstellation Energy Nuclear Group; Chief Financial
OfficerUniStar Nuclear Energy; Senior Vice President, FinanceConstellation Energy; and Chief Financial Officer, Constellation NewEnergyBeth S. Perlman

48

Senior Vice President (since January 2004), Chief Administrative Officer (since June 2007) and Chief Information Officer (since
April 2002) of Constellation Energy

NoneJonathan W. Thayer

37

Senior Vice President and Chief Financial Officer of Constellation Energy (since October 2008)

Vice President and Managing Director, Corporate Strategy and DevelopmentConstellation Energy; TreasurerConstellation
Energy; and Senior Vice President and Chief Financial OfficerBaltimore Gas and Electric Company


Officers are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or
understanding between any director or officer and any other person pursuant to which the director or officer was selected.

29

---



PART II

Item 5. Market for Registrant's Common Equity, Related Shareholder Matters, Issuer Purchases of Equity Securities, and Unregistered Sales of Equity and Use of  Proceeds

Stock Trading

Constellation Energy's common stock is traded under the ticker symbol CEG. It is listed on the New York and Chicago stock exchanges.

As
of January 30, 2009, there were 36,697 common shareholders of record.

Dividend Policy

Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There are no contractual
limitations on Constellation Energy paying common stock dividends.

Dividends
have been paid continuously since 1910 on the common stock of Constellation Energy, BGE, and their predecessors. Future dividends depend upon future earnings, our financial
condition, and other factors.

In
February 2009, we announced a quarterly dividend of $0.24 per share payable April 1, 2009 to holders of record on March 10, 2009. This is equivalent to an annual rate of
$0.96 per share.

Quarterly
dividends were declared on our common stock during 2008 and 2007 in the amounts set forth below.

BGE
pays dividends on its common stock after its Board of Directors declares them. There are no contractual limitations on BGE paying common stock dividends unless:



Common Stock Dividends and Price Ranges

2008

2007Price



PriceDividend
Declared

Dividend
DeclaredHigh

Low

High

LowFirst Quarter

$
0.4775

$
107.97

$
81.94

$
0.435

$
88.20

$
68.78Second Quarter


0.4775


94.62


78.74


0.435


95.57


82.71Third Quarter


0.4775


85.53


13.00


0.435


98.20


76.64Fourth Quarter


0.4775


30.17


21.70


0.435


104.29


85.81Total

$
1.91







$
1.74


30

---



Purchases of Equity Securities by the Issuer and Affiliated Purchases

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

Period

Total Number
of Shares
Purchased (1)

Average Price
Paid for Shares

Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs

Maximum Dollar
Amount of Shares
that May Yet Be
Purchased Under
the Plans and Programs
(at month end) (2)October 1 - October 31, 2008


3,075

$
23.96




$
750 millionNovember 1 - November 30, 2008


2,031


24.21





750 millionDecember 1 - December 31, 2008


725


25.01





750 millionTotal


5,831

$
24.18








Unregistered Sales of Equity Securities and Use of Proceeds

The sale and issuance of Constellation Energy's 8% Series A Convertible Preferred Stock to MidAmerican Energy Holdings Company
was reported previously on a Current Report on Form 8-K dated September 22, 2008. The sale and issuance of Constellation Energy's 8% Series B Preferred Stock to EDF
was reported previously on a Current Report on Form 8-K dated December 17, 2008. We also discuss these issuances inNote 9 to Consolidated
Financial Statements.

31

---





Table of Contents

Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

2008

2007

2006

2005

2004(In millions, except per share amounts)Summary of OperationsTotal Revenues

$
19,818.3

$
21,193.2

$
19,284.9

$
16,968.3

$
12,127.2Total Expenses


20,821.9


19,858.8


18,025.2


16,023.8


11,209.1Gains on Sales of Assets


25.5





73.8





(Loss) Income From Operations


(978.1
)

1,334.4


1,333.5


944.5


918.1Gains on Sales of CEP LLC equity





63.3


28.7





Other (Expense) Income


(52.3
)

158.6


66.1


65.5


25.5Fixed Charges


362.3


305.6


328.7


310.2


326.8(Loss) Income Before Income Taxes


(1,392.7
)

1,250.7


1,099.6


699.8


616.8Income Tax (Benefit) Expense


(78.3
)

428.3


351.0


163.9


118.4(Loss) Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles


(1,314.4
)

822.4


748.6


535.9


498.4(Loss) Income from Discontinued Operations, Net of Income Taxes





(0.9
)

187.8


94.4


41.3Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes











(7.2
)

Net (Loss) Income

$
(1,314.4
)
$
821.5

$
936.4

$
623.1

$
539.7(Loss) Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution

$
(7.34
)
$
4.51

$
4.12

$
2.98

$
2.88(Loss) Income from Discontinued Operations





(0.01
)

1.04


0.53


0.24Cumulative Effects of Changes in Accounting Principles











(0.04
)

(Loss) Earnings Per Common Share Assuming Dilution

$
(7.34
)
$
4.50

$
5.16

$
3.47

$
3.12Dividends Declared Per Common Share

$
1.91

$
1.74

$
1.51

$
1.34

$
1.14Summary of Financial ConditionTotal Assets

$
22,284.1

$
21,742.3

$
21,801.6

$
21,473.9

$
17,347.1Current Portion of Long-Term Debt

$
2,591.5

$
380.6

$
878.8

$
491.3

$
480.4CapitalizationLong-Term Debt

$
5,098.7

$
4,660.5

$
4,222.3

$
4,369.3

$
4,813.2Minority Interests


20.1


19.2


94.5


22.4


90.9Preference Stock Not Subject to Mandatory Redemption


190.0


190.0


190.0


190.0


190.0Common Shareholders' Equity


3,181.4


5,340.2


4,609.3


4,915.5


4,726.9Total Capitalization

$
8,490.2

$
10,209.9

$
9,116.1

$
9,497.2

$
9,821.0Financial Statistics at Year EndRatio of Earnings to Fixed Charges


N/A


3.84


4.05


3.04


2.71Book Value Per Share of Common Stock

$
15.98

$
29.93

$
25.54

$
27.57

$
26.81


N/ACalculation is not applicable as a result of the net loss for 2008.

We discuss items that affect comparability between years, including acquisitions and dispositions, accounting changes and other items, inItem 7.
Management's Discussion and Analysis.

32

---



Table of Contents

Baltimore Gas and Electric Company and Subsidiaries

2008

2007

2006

2005

2004(In millions)Summary of OperationsTotal Revenues

$
3,703.7

$
3,418.5

$
3,015.4

$
3,009.3

$
2,724.7Total Expenses


3,521.2


3,084.2


2,646.3


2,612.8


2,353.3Income From Operations


182.5


334.3


369.1


396.5


371.4Other Income (Expense)


29.6


26.8


6.0


5.9


(6.4
)Fixed Charges


139.9


125.3


102.6


93.5


96.2Income Before Income Taxes


72.2


235.8


272.5


308.9


268.8Income Taxes


20.7


96.0


102.2


119.9


102.5Net Income


51.5


139.8


170.3


189.0


166.3Preference Stock Dividends


13.2


13.2


13.2


13.2


13.2Earnings Applicable to Common Stock

$
38.3

$
126.6

$
157.1

$
175.8

$
153.1Summary of Financial ConditionTotal Assets

$
6,086.2

$
5,783.0

$
5,140.7

$
4,742.1

$
4,662.9Current Portion of Long-Term Debt

$
90.0

$
375.0

$
258.3

$
469.6

$
165.9CapitalizationLong-Term Debt

$
2,197.7

$
1,862.5

$
1,480.5

$
1,015.1

$
1,359.5Minority Interest


16.9


16.8


16.7


18.3


18.7Preference Stock Not Subject to Mandatory Redemption


190.0


190.0


190.0


190.0


190.0Common Shareholder's Equity


1,538.2


1,671.7


1,651.5


1,622.5


1,566.0Total Capitalization

$
3,942.8

$
3,741.0

$
3,338.7

$
2,845.9

$
3,134.2Financial Statistics at Year EndRatio of Earnings to Fixed Charges


1.50


2.84


3.60


4.22


3.75Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends


1.33


2.42


2.99


3.45


3.08


33

---





Table of Contents

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various
subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments inNote 3 to Consolidated Financial
Statements.

This
report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References
in this report to the "regulated business(es)" are to BGE. We discuss our business in more detail inItem 1. Businesssection and the risk
factors affecting our business inItem 1A. Risk Factorssection.

In
this discussion and analysis, we will explain the general financial condition of and the results of operations for Constellation Energy and BGE including:



As
you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss), which present the results of our operations for 2008, 2007, and 2006. We analyze and
explain the differences between periods in the specific line items of our Consolidated Statements of Income (Loss).

We
have organized our discussion and analysis as follows:



Strategy

We are pursuing a strategy of operating nuclear and non-nuclear generation facilities, providing energy and
energy-related products and services through our Customer Supply activities, and delivering electricity and gas to customers of BGE, our regulated utility located in central Maryland. Our merchant
energy business focuses on short-term and long-term purchases and sales of energy, capacity, and related products to various customers, including distribution utilities,
municipalities, cooperatives, and industrial, commercial, and governmental customers.

We
obtain this energy from both owned and contracted supply resources. Our generation fleet is strategically located in deregulated markets and includes various fuel types, such as
nuclear, coal, natural gas, oil, and renewable sources. In addition to owning generating facilities, we contract for power from other merchant providers, typically through power purchase agreements.
We use both our owned generation and our contracted generation to support our wholesale and retail Customer Supply operations.

We
are also in the forefront of the proposed development of new nuclear generation in the United States through our UniStar Nuclear Energy joint venture with EDF Group and related
entities (EDF). In addition, in December 2008, we entered into an investment agreement with EDF to sell to EDF a 49.99% interest in our nuclear generation and operation business (Investment
Agreement). EDF brings operational experience, global scale, and procurement leverage to the development of new nuclear plants in the United States and to the operation of our existing nuclear plants.
This new joint venture is expected to close in the third quarter of 2009, subject to receipt of regulatory approvals.

Collectively,
the integration of owned and contracted electric generation assets with origination, fuel procurement, and risk management expertise allows our merchant energy business to
earn incremental margin and more effectively manage energy and commodity price risk over geographic regions and time. Our focus is on providing solutions to customers' energy needs, and our Customer
Supply and Global Commodities operations add value to our owned and contracted generation assets by providing national market access, market infrastructure, real-time market intelligence,
risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity supports our Customer Supply and Global Commodities operations by providing a source of
reliable power supply.

We
expect BGE and our Customer Supply operation to grow through focused and disciplined expansion. At BGE, we are also focused on enhancing reliability, customer satisfaction, and
customer demand response initiatives.

Customer
choice, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies with these goals in mind: to improve
our competitive position, to anticipate and adapt to the business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality through the use of a
financial model that applies cash flow to reduce debt.

34

---



Table of Contents

As
a result of the significant events of 2008 as discussed in theBusiness Environmentsection, we are actively seeking to increase
available liquidity and reduce our business risk. Over the next one to two years, we expect to be in a transition period during which we will focus on executing the following objectives that we
believe will strengthen the Company:



The
execution of our strategy in the future will be affected by our ability to achieve these goals as well as by continued instability in financial and commodities markets. Execution of
our goals, including the pending asset divestitures, could have a substantial effect on the nature and mix of our business activities, as well as our financial position, results of operation and cash
flows.

In
addition, upon closing the transaction contemplated by our Investment Agreement with EDF, we expect to deconsolidate our subsidiary that owns our nuclear generation assets. In turn,
this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results.

Business Environment

Various factors affect our financial results. We discuss some of these factors in more detail in Item 1. BusinessCompetitionsection. We also discuss these various factors in
theForward Looking
StatementsandItem 1A. Risk Factorssections.

During
the last year, two events significantly influenced our business environment: the collapse of the credit markets and the extreme volatility in the energy markets. Throughout 2008,
volatility in the financial markets intensified, leading to dramatic declines in equity prices and substantially reducing liquidity in the credit markets. Most equity indices declined significantly,
the cost of credit default swaps and bond spreads increased substantially, and credit markets effectively ceased to be accessible for all but the most highly rated borrowers.

Major
financial institutions experienced significant financial difficulty, and widespread fears developed about the viability of any business that required access to credit markets to
support liquidity needs or that required substantial access to the capital markets to function, including Constellation Energy. By mid-September 2008, despite having announced a number of
actions to address our liquidity situation, we faced a sudden and immediate need to raise equity capital and take other steps to enhance our overall liquidity. As a result, on September 19,
2008, we entered into a definitive merger agreement with MidAmerican Energy Holdings Company (MidAmerican) to acquire Constellation Energy for $4.7 billion, which also provided us with an
immediate $1 billion cash infusion. In December 2008, however, we terminated the merger agreement with MidAmerican and entered into an agreement to sell a 49.99% interest in our nuclear
generation and operation business for $4.5 billion to EDF. Under that agreement, EDF provided us with a $1 billion cash infusion to replace the investment made by MidAmerican. We repaid
MidAmerican's $1 billion plus interest in January 2009. We discuss the termination of the merger with MidAmerican and our transaction with EDF in more detail in Note 15 to Consolidated Financial
Statements.

The
volatility of the global energy markets impacts our liquidity and collateral requirements as well as our credit risk. We discuss our liquidity and collateral requirements in the Financial Conditionsection. We continue to actively manage our credit risk to attempt to reduce the impact of a potential counterparty default. We
discuss our customer (counterparty) credit and other risks in more detail in theRisk Managementsection.

Competition

We face competition in the sale of electricity, natural gas, coal, and uranium in wholesale energy markets and to retail customers.

Various
states have moved to restructure their retail electricity and gas markets. The pace of deregulation in these states varies based on historical moves to competition and responses
to recent market events. While many states continue to support or expand retail competition and industry restructuring, other states that were considering deregulation

35

---



Table of Contents

have
slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation.

Specifically,
legislatures in a number of states are currently considering, to varying degrees, legislation to either eliminate or expand retail choice programs. In addition, many states
have initiated proceedings to reconsider the method of wholesale procurement for meeting their utilities' default/provider-of-last-resort (POLR) requirements. Both
the reconsideration of retail choice and possible new methodologies for wholesale procurement could affect our Customer Supply operation's future opportunities to service commercial and industrial
customers and the ability to provide wholesale products to utilities. The outcome of these efforts cannot be predicted, but they could have a material effect on our financial results.

All
BGE electricity and gas customers have the option to purchase electricity and gas from alternate suppliers.

We
discuss merchant competition in more detail inItem 1. BusinessCompetitionsection.

The
impacts of electric deregulation on BGE in Maryland are discussed inItem 1. BusinessBaltimore Gas and Electric
CompanyElectric BusinessElectric Competitionsection.

RegulationMaryland

Maryland PSC

In addition to electric restructuring, which we discuss inItem 1. BusinessElectric Competition
section, regulation by the Maryland Public Service Commission (Maryland PSC) significantly influences BGE's businesses. The Maryland PSC determines the rates that BGE can
charge customers of its electric distribution and gas businesses. The Maryland PSC incorporates into BGE's standard offer service rates the transmission rates determined by the Federal Energy
Regulatory Commission (FERC). BGE's electric rates are unbundled in customer billings to show separate components for delivery service (i.e. base rates), electric supply (commodity charge and
transmission), a universal service surcharge, and certain taxes. The rates for BGE's regulated gas business continue to consist of a delivery charge (base rate) and a commodity charge.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the
Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory, and legislative issues. On April 24, 2008, the Governor of
Maryland signed enabling legislation, which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement:



36

---



Table of Contents



Senate Bills 1 and 400

In June 2006, Maryland Senate Bill 1 was enacted, which among other things:



In
connection with these provisions of Senate Bill 1:



In
April 2007, Maryland Senate Bill 400 was enacted, which made certain modifications to Senate Bill 1. Pursuant to Senate Bill 400, the Maryland PSC was required to initiate several
studies, including studies relating to stranded costs, the costs and benefits of various options for re-regulation, and the structure of the electric industry in Maryland.

In
December 2007, the Maryland PSC issued an interim report addressing the costs and benefits of various options for re-regulation and recommending actions to be taken to
address an anticipated shortage of generation and transmission capacity in Maryland, which included implementation of demand response initiatives and requiring utilities to enter into
long-term power purchase contracts with suppliers.

The
Maryland PSC issued a final report in December 2008. In the final report, the Maryland PSC does not recommend returning the former utility generation assets to full cost of service
regulation, but rather recommends incremental, forward looking re-regulation when appropriate to ensure a reliable supply of electricity or to obtain economic benefits for customers. The
report also indicates that the Maryland PSC will investigate in 2009 whether, and on what terms, additional generation should be built in Maryland. In addition, the Maryland legislature continues to
review the structure of the Maryland energy markets and the need for re-regulation. We cannot at this time predict the ultimate outcome of these inquiries, studies, and recommendations or their actual
effect on our, or BGE's financial results, but it could be material.

We
discuss the market risk of our regulated electric business in more detail in theRisk Managementsection.

Base Rates

Base rates are the rates the Maryland PSC allows BGE to charge its customers for the cost of providing them delivery service, plus a profit. BGE has
both electric base rates and gas base rates.

BGE
may ask the Maryland PSC to increase base rates from time to time. The Maryland PSC historically has allowed BGE to increase base rates to recover its utility plant investment and
operating costs, plus a profit. Generally, rate increases improve the earnings of our regulated business because they allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates.

BGE's
most recently approved return on electric distribution rate base was 9.4% (approved in 1993). BGE's most recently approved return on gas rate base was 8.49% (approved in 2005).

According
to the terms of the 2008 Maryland settlement agreement, any future electric distribution base rate case filed by BGE will not result in increased distribution rates
prior to October 2009, and any increase in electric distribution revenue awarded will be capped at 5% with certain exceptions. Any subsequent electric distribution base rate case may not be filed
prior to August 1, 2010.
The agreement does not govern or affect our ability to recover costs associated with gas rates, federally approved transmission rates and charges, electric riders, tax increases, or increases
associated with standard offer service power supply auctions.

Revenue Decoupling

Beginning in 2008, the Maryland PSC approved, and BGE implemented, revenue decoupling for residential and small commercial customers to eliminate the
effect of abnormal weather and usage patterns per customer on its electric distribution volumes. This means that BGE's electric distribution revenues from residential and small commercial customers
reflect weather and usage that is considered normal for the month. Therefore, these revenues are affected primarily by customer growth. The Maryland PSC approved revenue decoupling for the majority of
our remaining commercial and industrial customers beginning February 1, 2009. We have a similar revenue decoupling mechanism in our gas business.

Demand Response and Advanced Metering Programs

In order to implement an advanced metering pilot program and a demand response program, BGE defers costs associated with these programs as a
regulatory asset and recovers these costs from customers in future periods. We discuss the advanced metering and demand response programs in more detail inItem 1.
BusinessBaltimore Gas and Electric CompanyElectric Load Management.

37

---



Table of Contents

Electric Commodity and Transmission Charges

We discuss BGE electric commodity and transmission charges (standard offer service), including the impact of the enactment of Senate Bill 1 in
Maryland, in theBusiness EnvironmentRegulationMarylandSenate Bills 1 and 400section.

Gas Commodity Charge

BGE charges its gas customers separately for the natural gas they purchase. The price BGE charges for the natural gas is based on a market-based
rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in theRegulated Gas BusinessGas Cost
Adjustmentssection and inNote 6 to Consolidated Financial Statements.

Federal Regulation

FERC

The FERC has jurisdiction over various aspects of our business, including electric transmission and wholesale natural gas and electricity sales. BGE
transmission rates are updated annually based on a formula methodology approved by FERC. The rates also include transmission investment incentives approved by FERC in orders issued in July and
November of 2007. We believe that FERC's continued commitment to fair and efficient wholesale energy markets should continue to result in improvements to competitive markets across various regions.

Since
1997, operation of BGE's transmission system has been under the authority of PJM Interconnection (PJM), the Regional Transmission Organization (RTO) for the
Mid-Atlantic region, pursuant to FERC oversight. As the transmission operator, PJM administers the energy markets and conducts day-to-day operations of the bulk
power system. The liability of transmission owners, including BGE, and power generators is limited to those damages caused by the gross negligence of such entities.

In
addition to PJM, RTOs exist in other regions of the country such as the Midwest, New York, and New England. Similar to PJM, these RTOs also administer the energy market for their
region and are responsible for operation of the transmission system and transmission system reliability. Our merchant energy business participates in these regional energy markets. These markets are
continuing to develop, and revisions to market structure are subject to review and approval by FERC. We cannot predict the outcome of any reviews at this time. However, changes to the structure of
these markets could have a material effect on our financial results.

FERC Initiatives

Ongoing initiatives at FERC have included a review of its methodology for the granting of market-based rate authority to sellers of electricity. FERC
has established interim tests that it uses to determine the extent to which companies may have market power in certain regions. Where FERC finds that market power exists, it may require companies to
implement measures to mitigate the market power in order to maintain market-based rate authority. We believe that our entities selling wholesale power continue to satisfy FERC's test for determining
whether to grant a public utility market-based rate authority.

In
November 2004, FERC eliminated through and out transmission rates between the Midwest Independent System Operator (MISO) and PJM and put in place Seams Elimination Charge/Cost
Adjustment/Assignment (SECA) transition rates, which are paid by the transmission customers of MISO and PJM and allocated among the various transmission owners in PJM and MISO. The SECA transition
rates were in effect from December 1, 2004 through March 31, 2006. FERC set for hearing the various compliance filings that established the level of the SECA rates and has indicated that
the SECA rates are being recovered from the MISO and PJM transmission customers subject to refund by the MISO and PJM transmission owners.

We
are a recipient of SECA payments, payer of SECA charges, and supplier to whom such charges may be shifted. Administrative hearings regarding the SECA charges concluded in May 2006,
and an initial decision from the FERC administrative law judge (ALJ) was issued in August 2006. The decision of the ALJ generally found in favor of reducing the overall SECA liability. The decision,
if
upheld, is expected to significantly reduce the overall SECA liability at issue in this proceeding. However, the ALJ also allowed SECA charges to be shifted to upstream suppliers, subject to certain
adjustments. Therefore, certain charges could be shifted to our wholesale marketing, risk management, and trading operation. This decision will be reviewed by FERC. We are unable to predict the timing
or final outcome of FERC's SECA rate proceeding. However, as the amounts collected under the SECA rates are subject to refund and the ultimate outcome of the proceeding establishing SECA rates is
uncertain, the result of this proceeding may have a material effect on our financial results.

Capacity Markets

In April 2006, FERC issued an initial order approving PJM's proposal to restructure its capacity market, which establishes the method by which we are
paid for making generating plant capacity available to PJM. The capacity market or Reliability Pricing Model (RPM) was approved by FERC in December 2006 after settlement proceedings. FERC in June and
November 2007 upheld the RPM settlement in response to requests for rehearing. An appeal of FERC's decisions on RPM was filed in January 2008 in the United States Court of Appeals for the District of
Columbia Circuit. Currently, we cannot predict with certainty what effect the results of these challenges will have on our, or BGE's, financial results.

Also
in January 2008 in connection with RPM, PJM filed revisions to its capacity market rules to reflect increased construction costs for new entry of generation (CONE), which was
rejected by FERC in April 2008. CONE is used in determining the price paid to capacity resources that clear in the PJM capacity auction. In September 2008, FERC directed PJM to consider revisions and
improvements to RPM to become effective prior to the May 2009 auction. In December 2008, PJM filed proposed tariff changes to RPM with FERC. PJM proposes significant revisions to RPM, including the
determination of CONE, the participation of energy efficiency and demand resources, and market power and mitigation rules.

38

---



Table of Contents

We
cannot predict the outcome of the FERC proceeding. However, the outcome could have a material effect on our financial results depending on the nature of the resulting changes to RPM.

In
May 2008, five state public service commissions, including the Maryland PSC, consumer advocates, and others filed a complaint against PJM at the FERC, alleging that the RPM produced
unreasonable prices during the period from June 1, 2008 through May 31, 2011. The complaint requests that FERC establish a refund effective date of June 1, 2008, reject the
results of the 2007/08 through 2010/11 RPM capacity auction results, and significantly reduce prices for capacity beginning as of June 1, 2008 through 2011/12. We, along with other power
suppliers and supplier trade groups, have filed protests to the complaint. In September 2008, FERC dismissed the complaint and in October 2008, the complainants requested a rehearing at FERC. We
cannot predict the outcome of this proceeding or the amount of refunds that may be owed by or due to us, if any. However, the outcome, and any refunds that are ultimately assessed, could have a
material impact on our financial results.

Three
major, high-voltage transmission lines have been announced that could enhance significantly the transfer capacity of the PJM transmission system from west to east. The
siting process either in the states or at FERC is uncertain, as is the likelihood that one or more of the transmission lines will be ultimately constructed. The construction of the transmission lines,
which could depress both capacity and energy prices for generation located in Maryland and elsewhere in the eastern part of PJM, could have a material effect on our financial results.

Other
market changes are routinely proposed and considered on an ongoing basis. Such changes will be subject to FERC's review and approval. We cannot predict the outcome of these
proceedings or the possible effect on our, or BGE's, financial results at this time.

NERC Reliability Standards

In compliance with the Energy Policy Act of 2005, FERC has approved the North American Electric Reliability Corporation (NERC) as the national energy
reliability organization. NERC will be responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. We are responsible for complying with
the standards in the regions in which we operate. NERC will have the ability to assess financial penalties for noncompliance, which could be material.

Weather

Merchant Energy Business

Weather conditions in the different regions of North America influence the financial results of our merchant energy business. Weather conditions can
affect the supply of and demand for electricity, natural gas, and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward
market, which may affect our results in any given period. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. The demand for and
price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time, thus we are not typically exposed
to the effects of extreme weather in all parts of our business at once.

BGE

Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very cold winters increase demand. Mild weather
reduces demand. Weather affects residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. The Maryland PSC has approved revenue
decoupling mechanisms which allow BGE to record monthly adjustments to the majority of our regulated electric and gas business distribution revenues to eliminate the effect of abnormal weather and
usage patterns. We discuss this further in theRegulationMaryland PSCRevenue Decoupling, Regulated Electric BusinessRevenue
DecouplingandRegulated Gas BusinessRevenue Decouplingsections.

Other Factors

A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative
products for our merchant energy business. These factors include:



These
factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional
differences in:



Other
factors also impact the demand for electricity and gas in our regulated businesses. These factors include the number of customers and usage per customer during a given period. We
use these terms later in our discussions of regulated electric and gas operations. In those sections, we discuss how these and other

39

---



Table of Contents

factors
affected electric and gas sales during the periods presented.

The
number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory.

Usage
per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When
the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downturn, our customers tend to consume less electricity and gas.

Environmental Matters and Legal Proceedings

We discuss details of our environmental matters inNote 12 to Consolidated Financial
StatementsandItem 1. BusinessEnvironmental Matterssection. We discuss details of our legal proceedings in Note 12 to Consolidated
Financial Statements. Some of this information is about costs that may be material to our financial results.

Accounting Standards Adopted and Issued

We discuss recently adopted and issued accounting standards inNote 1 to Consolidated Financial
Statements.

Critical Accounting Policies

Our discussion and analysis of financial condition and results of operations is based on our consolidated financial statements that
were prepared in accordance with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions when preparing financial statements. These
estimates and assumptions affect various matters, including:



These
estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management's control. As a result, actual amounts could materially differ
from these estimates.

Management
believes the following accounting policies represent critical accounting policies as defined by the Securities and Exchange Commission (SEC). The SEC defines critical
accounting policies as those that are both most important to the portrayal of a company's financial condition and results of operations and require management's most difficult, subjective, or complex
judgment, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods. We discuss our significant accounting
policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, inNote 1 to Consolidated Financial
Statements.

Accounting for Derivatives and Hedging Activities

We utilize a variety of derivative instruments in order to manage commodity price risk, interest rate risk, and foreign currency
risk. The accounting requirements for derivatives are governed by Statement of Financial Accounting Standards (SFAS) No. 133,Accounting for Derivative Instruments and
Hedging Activities, as amended and interpreted. Because of the extensive nature of its requirements that govern both accounting treatment and documentation, as well as the
complexity of the transactions within its scope, applying SFAS No. 133 requires management to exercise judgment in several areas, including the following:



As
discussed in more detail below, the exercise of management's judgment in these areas materially impacts our financial statements. While we believe we have appropriate controls in
place to apply SFAS No. 133, failure to meet its requirements, even inadvertently, could require the use of a different accounting treatment for the affected transactions. In addition,
interpretations of SFAS No. 133 continue to evolve, and a future change in accounting requirements also could affect our financial statements materially. We discuss derivatives and hedging
activities in more detail inNote 1andNote 13 to Consolidated Financial Statements.

Identification of Derivatives

We must evaluate new and existing transactions and agreements to determine whether they are derivatives. Identifying derivatives requires us to
exercise judgment in interpreting the definition of a derivative in SFAS No. 133 and applying that definition to each individual contract. If a contract is not a derivative, we cannot apply
SFAS No. 133, and we generally must record the effects of the contract in our financial statements upon delivery or settlement under the accrual method of accounting. In contrast, if a contract
is a derivative, we must apply SFAS No. 133, which provides for several possible accounting treatments as discussed more fully underAccounting
Treatmentbelow. As a result, the required accounting treatment and its impact on our financial statements can vary substantially depending upon whether a contract is a
derivative or a non-derivative.

Accounting Treatment

SFAS No. 133 permits several possible accounting treatments for derivatives that meet all of the applicable requirements of that standard.
SFAS No. 133 requires mark-to-market as the default accounting treatment for all derivatives unless they qualify, and we affirmatively designate them, for one of the
other accounting treatments. Derivatives designated for any of the other elective accounting treatments must meet specific, restrictive criteria prescribed by SFAS No. 133, both at the time of
designation and on an ongoing basis.

40

---



Table of Contents

The
permissible accounting treatments for derivatives are:



Each
of the accounting treatments that we use for derivatives affects our financial statements in substantially different ways as summarized below:

Recognition and MeasurementAccounting TreatmentBalance Sheet

Income StatementMark-to-market

  Recorded at fair value

  Changes in fair value recognized in earningsCash flow hedge

  Recorded at fair value
  Effective changes in fair value recognized in accumulated other comprehensive income

  Ineffective changes in fair value recognized in earnings
  Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurringFair value hedge

  Recorded at fair value
  Changes in fair value of the hedged asset or liability recorded as adjustment to its book value

  Changes in fair value recognized in earnings
  Changes in fair value of hedged asset or liability recognized in earningsNPNS (accrual)

  Fair value not recorded
  Accounts receivable or accounts payable recorded when derivative settles

  Changes in fair value not recognized in earnings
  Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed


We exercise judgment in determining which derivatives qualify for a particular accounting treatment under the provisions of SFAS No. 133
and its interpretations, including:



We
also exercise judgment in selecting the accounting treatment that we believe provides the most transparent presentation of the economics of the underlying transactions. Although
contracts may be eligible for hedge accounting or NPNS designation, SFAS No. 133 does not require all such contracts to be designated and accounted for identically. We generally elect accrual
or hedge accounting for our physical energy delivery activities (generation and customer supply) because accrual accounting more closely aligns the timing of earnings recognition, cash flows, and the
underlying business activities. By contrast, we generally apply mark-to-market accounting for risk management and trading activities because changes in fair value more closely
reflect the economic performance of the activity. However, we also use mark-to-market accounting for the following physical energy delivery activities:



41

---





Table of Contents

As a result of making these judgments, the selection of accounting treatments has a material impact on our financial position and results of operations. These
impacts affect several components of our financial statements, including assets, liabilities, and accumulated other comprehensive income. Additionally, the selection of accounting treatment also
affects the amount and timing of the recognition of earnings. The following table summarizes these impacts:

Accounting TreatmentEffect of Changes
in Fair Value on:Mark-to-market

Cash Flow Hedge

Fair Value Hedge

NPNSAssets and liabilities

  Increase or decrease in derivatives

  Increase or decrease in derivatives

  Increase or decrease in derivatives
  Decrease or increase in hedged asset or liability

  No impactAccumulated other comprehensive income (AOCI)

  No impact

  Increase or decrease for effective portion of hedge

  No impact

  No impactEarnings prior to settlement

  Increase or decrease

  Increase or decrease for ineffective portion of hedge

  Increase or decrease for change in derivatives
  Decrease or increase for change in hedged asset or liability
  Increase or decrease for ineffective portion

  No impactEarnings at settlement

  No impact

  Amounts in AOCI reclassified to earnings when hedged forecasted transaction affects earnings

  Hedged margin recognized in earnings

  Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed


Valuation

SFAS No. 133 requires us to record mark-to-market and hedge derivatives at fair value, which represents an exit price
for the asset or liability from the perspective of a market participant. An exit price is the price at which a market participant could sell an asset or transfer a liability to an unrelated party.
While some of our derivatives relate to commodities or instruments for which quoted market prices are available from external sources, many other commodities and related contracts are not actively
traded. Additionally, some contracts include quantities and other factors that vary over time. In these cases, we must use modeling techniques to estimate expected future market prices, contract
quantities, or both in order to determine fair value.

The
prices, quantities, and other factors we use to determine fair value reflect management's best estimates of inputs a market participant would consider. We record valuation
adjustments to reflect uncertainties associated with estimates inherent in the determination of fair value that are not incorporated in market price information or other market-based estimates we use
to determine fair value. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and
determining the level of such adjustments and changes in those levels. We discuss fair value measurements in more detail inNote 13 to Consolidated Financial
Statements.

The
judgments we are required to make in order to estimate fair value have a material impact on our financial statements. These judgments affect the selection, appropriateness, and
application of modeling techniques, the methods used to identify or estimate inputs to the modeling techniques, and the consistency in applying these techniques over time and across types of
derivative instruments. Changes in one or more of these judgments could have a material impact on the valuation of derivatives and, as a result, could also have a material impact on our financial
position or results of operations.

Impacts of Uncertainty

The accounting for derivatives and hedging activities involves significant judgment and requires the use of estimates that are inherently uncertain
and may change in subsequent periods. The effect of changes in assumptions and estimates could materially impact our reported amounts of revenues and costs and could be affected by many factors
including, but not limited to, the following:



42

---



Table of Contents



Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

Long-Lived Assets

We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they
are impaired when certain conditions exist. SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets,provides
the accounting requirements for impairments of long-lived assets. We are required to test our long-lived assets for recoverability whenever events or changes in circumstances
indicate that their carrying amount may not be recoverable. Examples of such events or changes are:



For
long-lived assets that can be classified as held for sale, we recognize an impairment loss to the extent their carrying amount exceeds their fair value less costs to
sell. For long-lived assets that we expect to hold and use, we recognize an impairment loss only if the carrying amount of an asset is not recoverable and exceeds its fair value. The
carrying amount of an asset is not recoverable if it exceeds the total undiscounted future cash flows expected to result from the use and eventual disposition of the asset. Therefore, when we believe
an impairment condition may have occurred, we estimate the undiscounted future cash flows associated with the asset at the lowest level for which identifiable cash flows are largely independent of the
cash flows of other assets and liabilities. This necessarily requires us to estimate uncertain future cash flows.

In
order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. To the extent
applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). If we are considering alternative courses of
action to recover the carrying amount of a long-lived asset (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the cash flows.

We
use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future
market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

If
we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we
must estimate fair value to determine the amount of any impairment loss. The estimation of fair value also involves judgment. We consider quoted market prices in active markets to the extent they are
available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the estimated future cash
flows associated with the asset using a single interest rate that is commensurate with the risk involved with such an investment or employ an expected present value method that probability-weights a
range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as discussed above with respect to undiscounted cash flows. Actual future market prices
and project costs could vary from those used in our estimates, and the impact of such variations could be material.

Gas Properties

We evaluate unproved property at least annually to determine if it is impaired under SFAS No. 19,Financial Accounting
and Reporting by Oil and Gas Producing Properties. Impairment for unproved property occurs if there are no firm plans to continue drilling, the lease is near its expiration, or
historical experience necessitates a valuation allowance.

Investments

We evaluate our equity-method and cost-method investments (for example, CEP and partnerships that own power projects) to determine
whether or not they are impaired. Accounting Principles Board (APB) Opinion No. 18,The Equity Method of Accounting for Investments in Common
Stock, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB No. 18 is whether the
investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

The
evaluation and measurement of impairments under the APB No. 18 standard involves the same uncertainties as described above for long-lived assets that we own
directly and account for in accordance with SFAS No. 144. Similarly, the estimates that we make with respect to our equity and cost-method investments are subject to variation, and
the impact of such variations could be material. Additionally, if the projects in which we hold these investments recognize an impairment under the provisions of SFAS No. 144, we would record
our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value under APB No. 18.

43

---



Table of Contents

We
continuously monitor issues that potentially could impact future profitability of our equity-method investments that own geothermal, coal, hydroelectric, fuel processing projects, as
well as our equity investments in our joint ventures and CEP, including environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in our Forward Looking StatementsandItem 1A. Risk Factorssections. However, should future events
cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of APB No. 18.

Current
California statutes and regulations require load-serving entities to increase their procurement of renewable energy resources and mandate statewide reductions in
greenhouse gas emissions. Given the need for electric power and the statutory and regulatory requirements increasing demand for renewable resource technologies, we believe California will continue to
foster an environment that supports the use of renewable energy and continues certain subsidies that will make renewable energy projects economical. However, should California legislation and
regulatory policies and federal energy policies fail to adequately support renewable energy initiatives, our equity-method investments in these types of projects could become impaired under the
provisions of APB No. 18, and any losses recognized could be material.

Debt and Equity Securities

Our available for sale investments in debt and equity securities, primarily our nuclear decommissioning trust fund assets, are subject to impairment
evaluations under FASB Staff Positions SFAS No. 115-1 and SFAS No. 124-1 (FSP 115-1 and 124-1),The Meaning of
Other-Than-Temporary Impairment and Its Application to Certain Investments.FSP 115-1 and 124-1 require us to determine whether
a decline in fair value of an investment below book value is other than temporary. If we determine that the decline in fair value is other than temporary, the cost basis of the investment must be
written down to fair value as a new cost basis. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these
securities is considered other than temporary and must be written down to fair value.

Goodwill

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and
other intangibles under the provisions of SFAS No. 142,Goodwill and Other Intangible Assets. We do not amortize goodwill. SFAS No. 142
requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of
the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived
assets as discussed on the previous page, which involves judgment. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the
extent that the carrying value of goodwill is greater than its fair value.

Asset Retirement Obligations

We incur legal obligations associated with the retirement of certain long-lived assets. SFAS No. 143, Accounting for Asset Retirement Obligations,provides the accounting for legal
obligations associated with the retirement of long-lived
assets. We incur such legal obligations as a result of environmental and other government regulations, contractual agreements, and other factors. The application of this standard requires significant
judgment due to the large number and diverse nature of the assets in our various businesses and the estimation of future cash flows required to measure legal obligations associated with the retirement
of specific assets. FASB Interpretation (FIN) 47,Accounting for Conditional Asset Retirement Obligationsan interpretation of FASB Statement
No. 143,clarifies that obligations that are conditional upon a future event are subject to the provisions of SFAS No. 143.

SFAS
No. 143 requires the use of an expected present value methodology in measuring asset retirement obligations that involves judgment surrounding the inherent uncertainty of the
probability, amount, and timing of payments to settle these obligations, and the appropriate interest rates to discount future cash flows. We use our best estimates in identifying and measuring our
asset retirement obligations in accordance with SFAS No. 143.

Our
nuclear decommissioning costs represent our largest asset retirement obligation. This obligation primarily results from the requirement to decommission and decontaminate our nuclear
generating facilities in connection with their future retirement. We utilize site-specific decommissioning cost estimates to determine our nuclear asset retirement obligations. However,
given the magnitude of the amounts involved, complicated and ever-changing technical and regulatory requirements, and the long time horizons involved, the actual obligation could vary from
the assumptions used in our estimates, and the impact of such variations could be material.

In
view of the significant number of assumptions underlying the decommissioning cost estimate, our estimate of the future cost of decommissioning is likely to continue to change over
time. For perspective, a 10% increase or decrease in our estimate of the future cost of decommissioning our nuclear plants would produce an approximately $96 million change to our asset
retirement obligation and an approximately $11 million change in our total annual amortization and accretion expenses.

Significant Events

Execution and Subsequent Termination of Merger Agreement with MidAmerican

On December 17, 2008, Constellation Energy and MidAmerican agreed to terminate the Agreement and Plan of Merger the parties
had entered into on September 19, 2008. As a result, we paid MidAmerican:



44

---



Table of Contents



Additionally,
we issued 19.9 million common shares and $1 billion of 14% Senior Notes to MidAmerican in connection with the conversion of the Series A Preferred
Stock.

We
discuss the termination of the merger in more detail inNote 15 to Consolidated Financial Statements.

Investment Agreement with EDF

On December 17, 2008, Constellation Energy and EDF and related entities entered into a series of transactions under which:



We
discuss these transactions in more detail inNote 15 to Consolidated Financial Statementsand the Series B Preferred
Stock inNote 9 to Consolidated Financial Statements.

Divestitures

In 2009, we made progress on many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business
risk.

In
January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation.

In
February 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. Simultaneously, we signed a letter of intent to enter into a related transaction
with an affiliate of the buyer under which that company would provide us with the gas supply needed to support our retail gas customer supply business, while reducing our credit requirements. We
expect that both of these sales will close by the end of the second quarter of 2009, subject to certain regulatory approvals and other standard closing conditions.

Collectively,
we expect both divestitures to return approximately $1 billion of currently posted collateral. In addition, we expect these divestitures to further reduce our
downgrade collateral requirements by approximately $400 million. These reductions are based on current commodity prices, the final terms of the transactions, and the timing of collateral to be
returned up to the close of the transactions, and, as a result, are subject to change.

We
discuss these divestitures in more detail inNote 3 to Consolidated Financial Statements.

Current Market Developments

As previously discussed in theBusiness Environmentsection, during 2008 the
financial markets experienced extreme volatility, and this volatility greatly reduced liquidity in the global credit markets. The following highlights the impacts of these developments on us:



45

---



Table of Contents



Commodity Prices

During 2008, the energy markets were affected by large fluctuations in commodity prices as indicated in the following table
summarizing changes in spot prices during 2008:

Increases (decreases) from December 31, 2007

Six months ended
June 30, 2008

Nine months ended
September 30, 2008

Year ended
December 31, 2008Power


33
%

(8
)%

(30
)%Natural gas


44
%

(5
)%

(30
)%Coal


153
%

58
%

(1
)%Crude oil


55
%

1
%

(40
)%


During the third and fourth quarters of 2008, prices for most commodities, including energy commodities, fell sharply after peaking early in July. The commodity
price environment contributed to the following impacts on our results:



Workforce Reduction Costs

During the third quarter of 2008, our merchant energy business approved a restructuring of its Customer Supply operations and
recognized a $2.5 million pre-tax charge.

During
the fourth quarter of 2008, we approved a broader restructuring of our operations and recognized a $19.7 million pre-tax charge.

We
discuss our workforce reduction costs in more detail inNote 2 to Consolidated Financial Statements.

Emission Allowances

During the second and third quarters of 2008, as a result of a July 11, 2008 decision by the United States Court of Appeals
for the D. C. Circuit that vacated the Clean Air Interstate Rule (CAIR) and the subsequent decline in market price for our emission allowance inventory, we recorded a write-down of our
emissions inventory and recognized partially offsetting gains on certain forward sales contracts. In December 2008, CAIR was reinstated and the market prices for our emission allowance inventory
increased. We reversed a portion of the previous write-downs of this inventory to reflect the subsequent increase in market prices. We discuss this net charge inNote 2
to Consolidated Financial Statements.

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired a partially completed gas-fired power generating facility in Alabama. We discuss this
acquisition in more detail inNote 15 to Consolidated Financial Statements.

West Valley Power Plant

On June 1, 2008, we acquired a gas-fired peaking plant in Utah. We discuss this acquisition in more detail in Note 15 to Consolidated Financial Statements.

Nufcor International Limited

On June 26, 2008, we acquired a uranium marketing services company in the United Kingdom. We discuss this acquisition in more detail in Note 15 to Consolidated Financial Statements.

Asset Sales

Working Interests in Gas Producing Property

In 2008, we sold the following:



We
discuss these asset sales in more detail inNote 2 to Consolidated Financial Statements.

46

---



Table of Contents

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture in which our merchant energy business owns a 50% ownership interest sold one of six dry bulk
vessels it owns for a gain to us of approximately $29 million. We discuss this sale in more detail inNote 2 to Consolidated Financial
Statements.

Financing Activities

In June 2008, we issued the following:



Also,
in June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013.

In
connection with the merger agreement with MidAmerican, we issued 10,000 shares of 8% Series A Convertible Preferred Stock to MidAmerican. Upon termination of the merger
agreement in December 2008, this Preferred Stock converted into $1 billion of 14% Senior Notes of Constellation Energy due December 31, 2009, 19.9 million common shares (9.9% of
our outstanding shares), and $418 million in cash.

In
connection with the Investment Agreement with EDF, Constellation Energy issued shares of mandatorily redeemable 8% Series B Preferred Stock for $1 billion, which shares
will be surrendered to us when EDF purchases its interest in our nuclear generation and operation business (and will be credited against the $4.5 billion purchase price, or, if the transaction
does not close, will be redeemed at the later of the termination date or December 31, 2009 for $1 billion of 10% Senior Notes due June 30, 2010). The $1 billion proceeds
from this issuance is restricted for the payment of our 14% Senior Notes held by MidAmerican. In January 2009, we repaid the 14% Senior Notes using these proceeds.

We
discuss our financing activities in more detail inNote 9 to Consolidated Financial Statements.

As
part of the Investment Agreement with EDF, EDF agreed to a put arrangement under which Constellation Energy could, at its option, sell to EDF certain non-nuclear
generation assets having an aggregate value of up to $2 billion. We discuss the Investment Agreement in more detail inNote 15 to Consolidated Financial
Statements.

In
addition, EDF has also agreed to provide us with a $600 million interim backstop liquidity facility. We discuss this facility in more detail in Note 8 to Consolidated Financial Statements.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of
Maryland, the Maryland PSC, and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory, and legislative issues. We discuss this settlement in
more detail inNote 2 to Consolidated Financial Statements.

Results of Operations

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, and then separately
discuss earnings for our operating segments. Significant changes in other income and expense, fixed charges, and income taxes are discussed in the aggregate for all segments in the Consolidated Nonoperating Income and
Expensessection.

As
discussed inPart I. Item 1 BusinessOverviewsection and in the StrategyandSignificant Eventssections, Constellation Energy's 2008 operating results were materially
impacted by a number of significant events, transactions, and resulting changes in the our strategic direction. The impact of these items has affected the comparability of our 2008 results to prior
periods and will alter Constellation Energy's operating results in the future. In this section, we highlight the 2008 impact of these items.

Overview

Results

2008

2007

2006(In millions, after-tax)Merchant energy

$
(1,357.4
)
$
679.2

$
580.1Regulated electric


1.1


97.9


120.2Regulated gas


37.2


28.8


37.0Other nonregulated


4.7


16.5


11.3(Loss) Income from continuing operations and before cumulative effects of changes in accounting principles


(1,314.4
)

822.4


748.6(Loss) income from discontinued operations





(0.9
)

187.8Net (Loss) Income

$
(1,314.4
)
$
821.5

$
936.4Other Items Included in Operations (after-tax)Impairments and other costs

$
(468.4
)
$
(12.2
)
$
Merger termination and strategic alternatives costs:Merger termination costs


(1,134.4
)




(5.7
)Strategic alternatives costs


(70.0
)




Maryland settlement credit


(126.5
)




Effective tax rate impact of Maryland settlement agreement


16.0





Impairment of nuclear decommissioning trust assets


(82.0
)




Emission allowance write down, net


(28.7
)




Non-qualifying hedges


(70.1
)

2.0


39.2Gain on sale of gas-fired plants








47.1Workforce reduction costs


(13.4
)

(1.4
)

(17.0
)Total Other Items

$
(1,977.5
)
$
(11.6
)
$
63.6Change from prior year

$
(1,965.9
)
$
(75.2
)


47

---



Table of Contents

2008

Our total net loss for 2008 exceeded net income for 2007 by $2,135.9 million, or $11.84 per share, mostly because of the
following:

2008 vs. 2007(in millions, after-tax)Generation gross margin

$
137Customer Supply gross margin


(79
)Global Commodities gross margin


(97
)Sale of upstream gas assets


162007 sale of CEP LLC equity


(39
)Hedge ineffectiveness


(26
)Credit losscoal supplier bankruptcy


(33
)Merchant operating expenses excluding bad debt expense, primarily labor and benefit costs


57Merchant bad debt expense


(19
)Merchant interest expense


(63
)Synthetic fuel facilities


(9
)Other nonregulated businesses


(12
)Total change in Other Items included in operations perOverviewResultstable


(1,966
)Interest and investment income


(35
)All other changes


32Total Change

$
(2,136
)


2007

Our total net income for 2007 decreased $114.9 million, or $0.66 per share, compared to 2006 mostly because of the following:

2007 vs. 2006(in millions, after-tax)Generation gross margin

$
98Customer supply and global commodities earnings, primarily higher gross margin, partially offset by higher operating expenses


23Absence of 2006 gain on saleHigh Desert


(189
)Gain on sales of CEP equity


21Synthetic fuel facilities


(34
)Regulated operations, primarily impact of Senate Bill 1 and higher operations and maintenance expenses


(31
)Total change in Other Items included in operations perOverviewResultstable


(75
)Interest and investment income


70All other changes


2Total Change

$
(115
)


Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our
merchant energy business inItem 1. BusinessCompetitionsection.

Our
merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation
assets and customer supply activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital.

We
are continuing to assess the ongoing capital requirements of the merchant energy business, including evaluating the proper size of our Customer Supply and Global Commodities
operations, and we are pursuing various strategic initiatives for our Global Commodities operation. As previously discussed, we have made substantial changes in our strategy. We discuss our strategy
in more detail in theStrategysection.

While
we have entered into definitive agreements in 2009 for the sale of a majority of our international commodities operation and our gas trading operation, the execution of our
strategy in the future will be affected by continued instability in financial, credit, and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our
business activities. In particular, upon closing the transactions contemplated by our Investment Agreement with EDF, we expect that our subsidiary that owns our nuclear generation assets will be
deconsolidated. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results. We
discuss our asset and operation divestitures in more detail inNote 3 to Consolidated Financial Statements.

We
record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect and based on the associated
accounting policies. We discuss our revenue recognition policies in theCritical Accounting Policiessection and in Note 1 to Consolidated Financial
Statements.

Our
Global Commodities operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through
structured transactions. As part of these activities, we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. We
manage these activities through daily value at risk and stop loss limits and liquidity guidelines, and they can have a material impact on our financial results. We discuss the impact of our trading
activities and value at risk in more detail in theMark-to-MarketandRisk
Managementsections.

48

---



Table of Contents

Results

2008

2007

2006(In millions)Revenues

$
16,772.8

$
18,744.5

$
17,166.2Fuel and purchased energy expenses


(13,791.4
)

(15,501.8
)

(14,256.3
)Operating expenses


(1,729.7
)

(1,791.8
)

(1,549.4
)Impairment losses and other costs


(741.8
)

(20.2
)

Workforce reduction costs


(15.4
)

(2.3
)

(28.2
)Merger termination and strategic alternatives costs


(1,204.4
)




(13.1
)Depreciation, depletion, and amortization


(287.1
)

(269.9
)

(258.7
)Accretion of asset retirement obligations


(68.4
)

(68.3
)

(67.6
)Taxes other than income taxes


(124.3
)

(110.2
)

(120.0
)Gains on sales of upstream gas assets


25.5





Gain on sale of gas-fired plants








73.8(Loss) Income from Operations

$
(1,164.2
)
$
980.0

$
946.7(Loss) Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax)

$
(1,357.4
)
$
679.2

$
580.1(Loss) Income from discontinued operations (after-tax)





(0.9
)

186.9Net (Loss) Income

$
(1,357.4
)
$
678.3

$
767.0Other Items Included in Operations (after-tax)Impairments and other costs

$
(468.4
)
$
(12.2
)
$
Merger termination and strategic alternatives costs


(1,204.4
)




(4.3
)Impairment of nuclear decommissioning trust assets


(82.0
)




Emission allowance write-down, net


(28.7
)




Gain on sale of gas-fired plants








47.1Non-qualifying hedges


(70.1
)

2.0


39.2Workforce reduction costs


(9.3
)

(1.4
)

(17.0
)Total Other Items

$
(1,862.9
)
$
(11.6
)
$
65.0


Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3
provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Revenues and Fuel and Purchased Energy Expenses

Our merchant energy business manages the revenues we realize from the sale of energy and energy-related products to our customers and our costs of
procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses, including all direct expenses, represents the gross margin of our merchant energy business, and this
measure is a useful tool for assessing the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by
analyzing the changes in gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our
portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

In
the third quarter of 2007, we changed the management of the wholesale procurement function for retail gas activities from our Customer Supply operation to our Global Commodities
operation. In connection with this change, we began to prospectively account for the underlying retail gas contracts as derivative contracts subject to mark-to-market
accounting, under which changes in fair value are recorded in revenues as they occur. This activity was previously accounted for on a gross basis and recorded in accrual revenues and fuel and
purchased energy expenses. The change to market-to-market accounting for this activity reduced both our accrual revenues and fuel and purchased energy expenses in 2008 and
2007. However, the change had a minimal impact on gross margin.

We
discuss our merchant energy revenues, fuel and purchased energy expenses, and gross margin below.

Revenues

Our
merchant energy revenues decreased $1,971.7 million in 2008 compared to 2007 and increased $1,578.3 million in 2007 compared to 2006 primarily due to the
following:

2008
vs. 2007

2007
vs. 2006(In millions)Change in Global Commodities mark-to-market revenues due to (unfavorable) favorable changes in power and gas prices

$
(403
)
$
71Change in contract prices and volume of business primarily related to our coal and international freight operation


(281
)

716Realization of higher contract prices on wholesale and retail load at our Global Commodities and Customer Supply operations


658


1,152All other (substantially all due to change in gas procurement activities)


(1,946
)

(361
)Total (decrease) increase in merchant revenues

$
(1,972
)
$
1,578


Fuel and Purchased Energy Expenses

Our
merchant energy fuel and purchased energy expenses decreased $1,710.4 million in 2008 compared to 2007 and increased $1,245.5 million in 2007 compared to
2006 primarily due to the following:

2008
vs. 2007

2007
vs. 2006(In millions)Change in Global Commodities mark-to-market expenses related to international coal purchase contracts

$
(106
)
$
18Change in contract prices and volume of business primarily related to our coal and freight operation


(238
)

733Realization of higher contract prices on wholesale and retail purchases at our Global Commodities and Customer Supply operations


710


813(Decrease) increase in synfuels expenses due to expiration of tax credits in 2007


(141
)

36All other (substantially all due to change in gas procurement activities)


(1,935
)

(354
)Total decrease in merchant energy revenues

$
(1,710
)
$
1,246


49

---



Table of Contents

Gross Margin

We
analyze our merchant energy gross margin in the following categories.



We
provide a summary of our gross margin for these three components of our merchant energy business as follows:

2008

2007

2006(Dollar amounts in millions)% of
Total



% of
Total



% of
TotalGross margin:Generation

$
1,956


66
%
$
1,700


53
%
$
1,490


51
%Customer Supply


765


25


889


27


764


26Global Commodities


260


9


654


20


656


23Total

$
2,981


100
%
$
3,243


100
%
$
2,910


100
%


In December 2006, we completed the sale of these gas-fired plants:

Facility

Capacity
(MW)

Unit Type

LocationHigh Desert


830

Combined Cycle

CaliforniaRio Nogales


800

Combined Cycle

TexasHolland


665

Combined Cycle

IllinoisUniversity Park


300

Peaking

IllinoisBig Sandy


300

Peaking

West VirginiaWolf Hills


250

Peaking

Virginia


This sale impacted our results of operation and cash flows for 2006 when compared to 2007. We discuss the sale of these gas-fired
generating facilities inNote 2 to Consolidated Financial Statements.

Generation

The $256 million increase in Generation gross margin in 2008 compared to 2007 is primarily due to the following:



The
$210 million increase in generation gross margin in 2007 compared to 2006 is primarily due to approximately $290 million increase from higher energy prices for the
output of our generating assets in the PJM and New York regions based on prices established at the end of 2006 (see Global Commodities discussion below for impact of price changes during 2007). This
increase was partially offset by lower gross margin due to the absence of approximately $80 million of gross margin associated with the gas plants that were sold in December 2006.

Customer Supply

The $124 million decrease in Customer Supply gross margin in 2008 compared to 2007 is primarily due to the following:



50

---



Table of Contents



These
decreases were partially offset by approximately $64 million of higher gross margin related to our retail gas operation primarily due to the acquisition of Cornerstone
Energy on July 1, 2007.

The
$125 million increase in Customer Supply gross margin in 2007 compared to 2006 is primarily due to approximately $182 million of higher realization of contracts
executed in prior periods and new contracts executed, including the portfolio of contracts acquired in the southeast United States, primarily for our wholesale and retail power operations. These
increases were partially offset by the following:



Global Commodities

We present Global Commodities results in the following categories:



As
previously discussed in theSignificant Eventssection, the energy markets were affected by substantial volatility in commodity prices
during 2008. These market impacts are reflected in the $394 million decrease in gross margin from our Global Commodities operation during 2008 compared to the same period of 2007 primarily due
to $698 million of lower gross margin in our portfolio management and trading activities, partially offset by $208 million of higher gross margin in our structured products portfolio and
$96 million of higher gross margin in our energy investments portfolio. We discuss these changes below.

The
$698 million of lower gross margin related to our portfolio management and trading operation are due to the following:



These
decreases in gross margin related to our portfolio management and trading activities are partially offset by higher gross margin of:



The
$2 million decrease in gross margin from our Global Commodities operation in 2007 as compared to the same period in 2006 is primarily due to lower gross margin of
$43 million in our portfolio management and trading operation and $34 million of lower gross margin in our structured products

51

---



Table of Contents

portfolio,
partially offset by higher gross margin of $75 million related to our energy investments portfolio. We discuss these changes below.

The
decrease in gross margin of $43 million as a result of portfolio management and trading is primarily related to the following:



These
decreases were partially offset by $168 million of higher gross margin related to our portfolio of contracts subject to mark-to-market accounting,
including higher earnings of $28 million related to increased origination gains primarily associated with nonderivative contracts that were amended to reduce counterparty nonperformance risk,
resulting in the contracts becoming derivatives for which mark-to-market accounting is required. We discuss these transactions in more detail in the Mark-to-Marketsection,

The
decrease in gross margin of $34 million for the structured products portfolio is primarily related to fewer contract terminations and sales during 2007 as compared to 2006.

These
decreases were partially offset by an increase in gross margin of $75 million from the energy investments portfolio, primarily related to the following:



Mark-to-Market

Mark-to-market results include net gains and losses from origination, trading, and risk management activities for which we
use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policiessection and inNote 1 to Consolidated Financial Statements.

As
a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market earnings will
fluctuate. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in theRisk
Managementsection. The primary factors that cause fluctuations in our mark-to-market results are:



As
discussed earlier, we are currently assessing the ongoing capital requirements of the merchant energy business and are pursuing various alternative strategies. Additionally, we have
focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short-term liquidity requirements. These actions may impact the future
results of the merchant energy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market accounting.

The
primary components of mark-to-market results are origination gains and gains and losses from risk management and trading activities.

Origination
gains arise primarily from contracts that our Global Commodities operation structures to meet the risk management needs of our customers or relate to our trading activities.
Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction.

Risk
management and tradingmark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio,
including the effects of changes in valuation adjustments. In addition to our fundamental risk management and trading activities, we also use non-trading derivative contracts subject to
mark-to-market accounting to manage our exposure to changes in market prices as a result of our gas
transportation and storage activities, while in general the underlying physical transactions related to our gas transportation and storage and freight activities are accounted for on an accrual basis.
We use other non-trading derivative transactions subject to mark-to-market accounting to manage our exposure to changes in market prices related to our other
activities that are accounted for on an accrual basis.

We
discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our
net mark-to-market energy asset later in this section.

52

---



Table of Contents

Mark-to-market
results were as follows:

2008

2007

2006(In millions)Unrealized mark-to-market resultsOrigination gains

$
73.8

$
41.9

$
13.5Risk management and tradingmark-to-marketUnrealized changes in fair value


159.8


500.8


387.4Changes in valuation techniques








Reclassification of settled contracts to realized


48.2


(369.3
)

(372.1
)Total risk management and tradingmark-to-market


208.0


131.5


15.3Total unrealized mark-to-market*


281.8


173.4


28.8Realized mark-to-market


(48.2
)

369.3


372.1Total mark-to-market results

$
233.6

$
542.7

$
400.9


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

The
net decrease in risk management and trading gains of $341.0 million was primarily due to:



The
risk management and trading results were partially offset by:



Total
mark-to-market results increased $141.8 million during the year ended December 31, 2007 compared to the same period of 2006 primarily due to:



We
discuss the increase in origination gains below.

The
$113.4 million in higher gains from unrealized changes in fair value was primarily driven by:



These
gains were partially offset by $42 million of losses related to unfavorable price movements on certain economic hedges of accrual transactions that do not qualify for or are
not designated as cash-flow hedges, primarily relating to gas transportation and storage and freight activities.

Origination
gains arose primarily from:



The
recognition of origination gains is generally dependent on the availability of sufficient observable market data that validates the initial fair value of the contract. Liquidity and
market conditions impact our ability to identify sufficient, objective market-price information to permit recognition of origination gains. As a result, while our strategy and competitive position
provide the opportunity to continue to originate such transactions, the level of origination gains we are able to recognize may vary from year to year as a result of the number, size, and market-price
transparency of the individual transactions executed in any period.

During
2008, our Global Commodities operation amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these
amendments, the revised contracts are derivatives subject to mark-to-market accounting under SFAS No. 133. The change in accounting for these contracts from
nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the table above.

During
2007, our Global Commodities operation amended certain nonderivative power sales contracts such that the new contracts became derivatives subject to
mark-to-market accounting under SFAS No. 133. Simultaneous with the amending of the nonderivative contracts, we executed at current market prices several new offsetting
derivative power purchase contracts subject to mark-to-market accounting. The combination of these transactions resulted in substantially all of the origination gains presented
for 2007 in the preceding table,

53

---



Table of Contents

as
well as mitigated our risk exposure under the amended contracts.

The
origination gains in 2007 from these transactions was partially offset by approximately $12 million of losses in our accrual portfolio due to the reclassification of losses
related to cash-flow hedges previously established for the amended nonderivative contracts from "Accumulated other comprehensive loss" into earnings. In the absence of these transactions,
the economic value represented by the origination gains and the losses associated with cash-flow hedges would have been recognized over the remaining term of the contracts, which extended
through the first quarter of 2009.

Derivative Assets and Liabilities

Derivative assets and liabilities consisted of the following:

At December 31,

2008

2007(In millions)Current assets

$
1,465.0

$
760.6Noncurrent assets


851.8


1,030.2Total assets


2,316.8


1,790.8Current liabilities


1,241.8


1,134.3Noncurrent liabilities


1,115.0


1,118.9Total liabilities


2,356.8


2,253.2Net derivative position

$
(40.0
)
$
(462.4
)Composition of net derivative exposure:Hedges

$
(1,837.6
)
$
(937.6
)Mark-to-market


1,485.9


673.0Net cash collateral included in derivative balances


311.7


(197.8
)Net derivative position

$
(40.0
)
$
(462.4
)


As discussed in ourCritical Accounting Policiessection, our "Derivative assets and liabilities" include
contracts accounted for as hedges and those accounted for on a mark-to-market basis. These amounts are presented in our Consolidated Balance Sheets after the impact of netting,
which is discussed in more detail inNote 1 to Consolidated Financial Statements. Due to the impacts of commodity prices, the number of open
positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities in our Consolidated Balance Sheets, we believe an evaluation of the
net position is the most relevant measure, and is discussed in more detail below. However, we present our gross derivatives as required by SFAS No. 157,Fair Value
Measurements, inNote 13 to Consolidated Financial Statements.

The
increase of $900.0 million in our net derivative liability subject to hedge accounting since December 31, 2007 was due primarily to $1,232 million of unrealized
losses associated with existing hedge positions due to unfavorable price changes. These losses were partially offset by $332 million related to the settlement of
out-of-the-money cash-flow hedges during 2008. To the extent that these hedges are effective, these unrealized losses will be offset by unrealized gains
on the related hedged transactions that will be realized when those transactions affect earnings. We record any hedge ineffectiveness in earnings as it occurs.

The
following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during 2008 and 2007:

2008

2007(In millions)Fair value beginning of year




$
673.0




$
454.1Changes in fair value recorded in earningsOrigination gains

$
73.8




$
41.9Unrealized changes in fair value


159.8





500.8Changes in valuation techniques








Reclassification of settled contracts to realized


48.2





(369.3
)Total changes in fair value





281.8





173.4Changes in value of exchange-listed futures and options





571.3





18.6Net change in premiums on options





19.2





(19.0
)Contracts acquired











83.8Other changes in fair value





(59.4
)




(37.9
)Fair value at end of year




$
1,485.9




$
673.0


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



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



54

---



Table of Contents



Effective
January 1, 2008, we adopted SFAS No. 157 for our financial assets and liabilities, which defines fair value, establishes a framework for measuring fair value, and
requires certain disclosures about fair value measurements. Fair value is the price that a market participant would receive to sell an asset or pay to transfer a liability in an orderly transaction
between market participants at the measurement date (exit price).

Consistent
with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008 we recorded a
pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings
totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial. We discuss SFAS No. 157 and how we determine fair value in more detail
inNote 13 to Consolidated Financial Statements.

The
settlement terms of the portion of our net derivative asset subject to mark-to-market accounting and sources of fair value based on the fair value hierarchy
established by SFAS No. 157 are as follows as of December 31, 2008:

Settlement Term2009

2010

2011

2012

2013

2014

Thereafter

Fair Value(In millions)Level 1

$
(19.9
)
$


$


$


$


$


$


$
(19.9
)Level 2


520.0


(45.8
)

196.8


99.9


(16.1
)

(0.4
)

(0.6
)

753.8Level 3


312.7


343.9


147.4


(38.8
)

(11.2
)

2.9


(4.9
)

752.0Total net derivative asset (liability) subject to mark-to-market accounting

$
812.8

$
298.1

$
344.2

$
61.1

$
(27.3
)
$
2.5

$
(5.5
)
$
1,485.9


Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors
including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. Additionally, because the depth and liquidity of the
power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Future market
prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

We
manage our mark-to-market risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each
contract. Accordingly, we manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product
(e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery
period (e.g., by month and year).

The
electricity, fuel, and other energy contracts we hold have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more.
Because an active, liquid electricity futures market comparable to that for other commodities has not developed, many contracts are direct contracts between market participants and are not
exchange-traded or financially settling contracts that can be readily offset in their entirety through an exchange or other market mechanism. Consequently, we and other market participants generally
realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.

In
order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of
our long-term contracts in their entirety, we may not realize the entire value reflected in the preceding table. However, based upon the nature of our Global Commodities operation, we
expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with
their terms. Generally, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

Operating Expenses

Our merchant energy business operating expenses decreased $62.1 million during 2008 compared to 2007 mostly due to lower performance-based
labor and benefit costs at our merchant energy business of $129.2 million, partially offset by higher non-labor operating expenses of $67.1 million, which included
approximately $32 million of higher bad debt expense.

Our
merchant energy business operating expenses increased $242.4 million during 2007 compared to 2006 mostly due to an increase at our Global Commodities and Customer Supply
operations totaling $218.4 million, primarily related to the continued growth of this operation and higher compensation and benefit costs.

55

---



Table of Contents

Impairments and Other Costs

Our impairments and other costs are discussed in more detail inNote 2 to Consolidated Financial
Statements.

Workforce Reduction Costs

Our merchant energy business recognized expenses associated with our workforce reduction efforts as discussed in more detail in Note 2 to Consolidated Financial Statements.

Merger Termination and Strategic Alternatives Costs

We discuss costs related to the terminated merger with MidAmerican, the conversion of the Series A Preferred Stock, the Investment Agreement
with EDF and our pursuit of other strategic alternatives inNote 2 to Consolidated Financial Statements.

Depreciation, Depletion and Amortization Expense

Merchant energy depreciation, depletion, and amortization expenses increased $17.2 million in 2008 compared to 2007 mostly due to increased
depletion expenses related to our upstream natural gas operations as a result of increased drilling and production, partially offset by the cessation of operations at our synfuel facilities in
December 2007.

Merchant
energy depreciation, depletion, and amortization expenses increased $11.2 million in 2007 compared to 2006 mostly due to:



These
increases were partially offset by $29.0 million primarily related to the absence of depreciation associated with the gas plants that were sold in December 2006.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $14.1 million in 2008 compared to 2007, primarily due to $9.8 million in higher property and
franchise taxes at our Generation operation, $2.9 million of higher gross receipts taxes at our retail customer supply operation, and $1.4 million of higher production taxes related to
our upstream gas producing properties.

Taxes
other than income taxes decreased $9.8 million in 2007 compared to 2006, primarily due to $5.8 million lower gross receipts tax at our retail customer supply
operation and a $4.2 million decrease due to the sale of our gas-fired plants.

Gains on Sale of Assets

During 2008, we recognized net gains of $25.5 million, including a $14.3 million gain, net of the minority interest gain of
$0.7 million, related to the sale of our working interests in oil and natural gas producing wells in Oklahoma to Constellation Energy Partners that was completed in the first quarter of 2008.

We
discuss our gains on sale of assets in more detail inNote 2 to Consolidated Financial Statements.

Regulated Electric Business

Our regulated electric business is discussed in detail inItem 1. BusinessElectric
Businesssection.

Results

2008

2007

2006(In millions)Revenues

$
2,679.7

$
2,455.7

$
2,115.9Electricity purchased for resale expenses


(1,880.1
)

(1,500.4
)

(1,167.8
)Operations and maintenance expenses


(380.5
)

(376.1
)

(351.3
)Workforce reduction costs


(4.6
)




Merger termination and strategic alternatives costs *








(3.3
)Depreciation and amortization


(184.2
)

(187.4
)

(181.5
)Taxes other than income taxes


(139.1
)

(140.2
)

(134.9
)Income from Operations

$
91.2

$
251.6

$
277.1Net Income

$
1.1

$
97.9

$
120.2Other Items Included in Operations (after-tax):Maryland settlement credit

$
(126.5
)
$


$
Effective tax rate impact of Maryland settlement agreement


16.0





Workforce reduction costs


(2.8
)




Merger termination and strategic alternatives costs *








(0.8
)Total Other Items

$
(113.3
)
$


$
(0.8
)


Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a
reconciliation of operating results by segment to our Consolidated Financial Statements.

Net
income from the regulated electric business decreased $96.8 million in 2008 compared to 2007, primarily due to the impact of the Maryland settlement credit of
$126.5 million after-tax, partially offset by the impact on the effective tax rate of the Maryland settlement credit of $16.0 million and reduced depreciation and
amortization expense of $2.0 million after-tax.

Net
income from the regulated electric business decreased $22.3 million in 2007 compared to 2006, primarily due to the following:



The
decrease was partially offset by an increase in revenues less electricity purchased for resale expenses of $4.4 million after-tax, which includes the impact of
Senate Bill 1 credits.

56

---



Table of Contents

Electric Revenues

The changes in electric revenues in 2008 and 2007 compared to the respective prior year were caused by:

2008

2007(In millions)Distribution volumes

$
(15.0
)
$
19.5Maryland settlement credit


(189.1
)

Revenue decoupling


12.5


Standard offer service


79.4


267.8Rate stabilization credits


287.3


34.6Rate stabilization recovery


43.1


36.1Financing credits


(9.1
)

(7.5
)Senate Bill 1 credits


3.3


(29.7
)Total change in electric revenues from electric system sales


212.4


320.8Other


11.6


19.0Total change in electric revenues

$
224.0

$
339.8


Distribution Volumes

Distribution volumes are the amount of electricity that BGE delivers to customers in its service territory.

The
percentage changes in our electric system distribution volumes, by type of customer, in 2008 and 2007 compared to the respective prior year were:

2008

2007Residential


(2.6
)%

3.7
%Commercial


(3.6
)

3.6Industrial


(6.3
)

0.2


In 2008, we distributed less electricity to residential and commercial customers due to milder weather and decreased usage per customer, partially offset by an
increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer.

In
2007, we distributed more electricity to residential customers due to colder winter weather and an increased number of customers, partially offset by decreased usage per customer. We
distributed more electricity to commercial customers due to increased usage per customer, colder winter weather, and an increased number of customers. We distributed essentially the same amount of
electricity to industrial customers.

Maryland Settlement Credit

As discussed in more detail inNote 2 to Consolidated Financial Statements, BGE entered into a
settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit totaling $170 per customer. The estimated settlement of $188.2 million
was accrued in the second quarter of 2008 and a total of $189.1 million was credited to customers in the third and fourth quarters of 2008.

Revenue Decoupling

Beginning in 2008, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from residential and small
commercial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. This means our monthly electric distribution revenues for
residential and small commercial customers are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be
affected by actual weather or usage conditions.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Maryland's Senate Bill 1
related to residential electric rates in theBusiness EnvironmentRegulationMarylandSenate Bills 1 and 400section.

Standard
offer service revenues increased in 2008 compared to 2007 mostly due to higher standard offer service rates, partially offset by lower standard offer service volumes.

Standard
offer service revenues increased in 2007 compared to 2006, primarily due to an increase in the standard offer service rates following the expiration of residential rate freeze
service in July 2006, partially offset by lower standard offer service volumes.

Rate Stabilization Credits

As a result of Senate Bill 1, we were required to defer from July 1, 2006 until May 31, 2007 a portion of the full market rate increase
resulting from the expiration of the residential rate freeze. In addition, we offered a plan also required under Senate Bill 1 allowing residential customers the option to defer the transition to
market rates from June 1, 2007 until January 1, 2008.

Revenues
in 2008 increased compared to 2007 due to lower rate stabilization credits as a result of the expiration of the rate stabilization plans.

In
2007 compared to 2006, revenues increased due to lower rate stabilization credits provided to residential electric customers as a result of the end of the first deferral period on
May 31, 2007, partially offset by the additional deferrals during the second deferral period, which ended on December 31, 2007.

Rate Stabilization Recovery

In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that ended on May 31, 2007. In April 2008, BGE
began recovering amounts deferred during the second rate deferral period that ended on December 31, 2007. The recovery of the second rate deferral will occur over a 21-month period
that began April 1, 2008 and ending on December 31, 2009. The recovery of the first rate stabilization plan will occur over approximately ten years.

57

---



Table of Contents

Financing Credits

Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to
compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds. We discuss the rate stabilization bonds in more detail in Note 9 to Consolidated
Financial Statements.

Senate Bill 1 Credits

As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the
amount collected from all BGE electric customers for the decommissioning of our Calvert Cliffs Nuclear Power Plant and to suspend collection of the residential return component of the administrative
charge collected through residential SOS rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection
of the residential return component of the administration charge in rates and to provide all residential electric customers a credit for the residential return component of the administrative charge.
Under the Maryland settlement agreement, which is discussed in more detail inNote 2 to Consolidated Financial Statements, BGE was allowed to
resume collection of the residential return portion of the administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.

The
increase in revenues during 2008 compared to 2007 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended
under the Maryland settlement agreement, partially offset by lower distribution volumes.

Electricity Purchased for Resale Expenses

Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs
do not include the cost of electricity purchased by delivery service only customers. The following table summarizes our regulated electricity purchased for resale expenses:

2008

2007

2006(In millions)Actual costs

$
1,821.1

$
1,759.2

$
1,489.7Deferral under rate stabilization plan





(287.3
)

(321.9
)Recovery under rate stabilization plans


59.0


28.5


Electricity purchased for resale expenses

$
1,880.1

$
1,500.4

$
1,167.8


Actual Costs

BGE's actual costs for electricity purchased for resale increased $61.9 million for 2008 compared to 2007, primarily due to higher contract
prices to purchase electricity for our customers, partially offset by lower volumes.

BGE's
actual costs for electricity purchased for resale increased $269.5 million for 2007 compared to 2006, primarily due to higher contract prices to purchase electricity for our
residential customers following the expiration of contracts that were executed in 2000 as part of the implementation of electric deregulation in Maryland, partially offset by lower volumes.

Deferral under Rate Stabilization Plan

The deferral of the difference between our actual costs of electricity purchased for resale and what we are allowed to bill customers under Senate
Bill 1 ended on December 31, 2007. Since July 1, 2006, we have deferred $609.2 million in electricity purchased for resale expenses. In 2007, we deferred $287.3 million in
electricity purchased for resale expenses. These
deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets. We discuss the provisions of Senate Bill 1 related to residential
electric rates in theBusiness EnvironmentRegulationMarylandSenate Bills 1 and 400section.

Recovery under Rate Stabilization Plans

In late June 2007, we began recovering previously deferred amounts from customers related to our first rate stabilization plan. In April 2008, we
began recovering previously deferred amounts from customers related to our second rate stabilization plan. We recovered $59.0 million in 2008 and $28.5 million in 2007 in deferred
electricity purchased for resale expenses. These collections secure the payment of principal and interest and other ongoing costs associated with rate stabilization bonds issued by a subsidiary of BGE
in June 2007.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses increased $4.4 million in 2008 compared to 2007 mostly due to increased uncollectible
accounts receivable expense of $14.2 million, partially offset by $9.0 million of lower labor and benefit costs.

Regulated
operations and maintenance expenses increased $24.8 million in 2007 compared to 2006 mostly due to higher labor and benefit costs and the impact of inflation on other
costs of $16.9 million, customer education in relation to rate stabilization of $5.3 million, and increased uncollectible accounts receivable expense of $2.9 million.

Workforce Reduction Costs

During the fourth quarter of 2008, we executed a restructuring of the workforce. We recognized a $4.6 million pre-tax charge in
2008 related to this reduction in force.

We
incurred no workforce reduction costs in 2007 or 2006.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense decreased $3.2 million in 2008 compared to 2007, primarily due to
$10.0 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of
the Maryland settlement agreement. The Maryland settlement agreement is discussed in more detail inNote 2 to Consolidated

58

---



Table of Contents

Financial Statements. This decrease was partially offset by additional property placed in service in 2008.

Regulated
electric depreciation and amortization expense increased $5.9 million in 2007 compared to 2006, primarily due to additional property placed in service.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5.3 million in 2007 in comparison with 2006, primarily due to increased property taxes.

Regulated Gas Business

Our regulated gas business is discussed in detail inItem 1. BusinessGas
Businesssection.

Results

2008

2007

2006(In millions)Revenues

$
1,024.0

$
962.8

$
899.5Gas purchased for resale expenses


(694.5
)

(639.8
)

(581.5
)Operations and maintenance expenses


(157.3
)

(157.5
)

(144.8
)Workforce reduction costs


(1.8
)




Merger termination and strategic alternatives costs *








(1.4
)Depreciation and amortization


(43.7
)

(46.8
)

(46.0
)Taxes other than income taxes


(35.4
)

(36.1
)

(33.8
)Income from Operations

$
91.3

$
82.6

$
92.0Net Income

$
37.2

$
28.8

$
37.0Other Items Included in Operations (after-tax):Workforce reduction costs

$
(1.0
)
$


$
Merger termination and strategic alternatives costs *








(0.4
)Total Other Items

$
(1.0
)
$


$
(0.4
)


Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3
provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Net income from the regulated gas business increased $8.4 million in 2008 compared to 2007, primarily due to an increase in revenues less gas purchased
for resale expenses of $4.0 million after-tax and reduced depreciation and amortization expense of $1.9 million after-tax.

Net
income from the regulated gas business decreased $8.2 million in 2007 compared to 2006, primarily due to increased operations and maintenance expenses of $7.7 million
after-tax.

Gas Revenues

The changes in gas revenues in 2008 and 2007 compared to the respective prior year were caused by:

2008

2007(In millions)Distribution volumes

$
(5.1
)
$
19.3Base rates


(0.1
)

0.2Revenue decoupling


6.2


(20.1
)Gas cost adjustments


20.3


74.4Total change in gas revenues from gas system sales


21.3


73.8Off-system sales


40.3


(11.2
)Other


(0.4
)

0.7Total change in gas revenues

$
61.2

$
63.3


Distribution Volumes

The percentage changes in our distribution volumes, by type of customer, in 2008 and 2007 compared to the respective prior year were:

2008

2007Residential


(3.9
)%

17.7
%Commercial


(3.1
)

14.6Industrial


2.8


(11.3
)


In 2008, we distributed less gas to residential customers and commercial customers due to decreased usage per customer, partially offset by an increased number of
customers. We distributed more gas to industrial customers mostly due to increased usage per customer, partially offset by a decreased number of customers.

In
2007, we distributed more gas to residential customers due to colder weather, increased usage per customer and an increased number of customers. We distributed more gas to commercial
customers due to an increased number of customers and colder weather, partially offset by decreased usage per customer. We distributed less gas to industrial customers mostly due to decreased usage
per customer.

Revenue Decoupling

The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage
patterns per customer on our gas distribution volumes. This means our monthly gas distribution revenues are based on weather and usage that is considered "normal" for the month. Therefore, while these
revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

59

---



Table of Contents

Gas Cost Adjustments

We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1 to Consolidated Financial Statements. However, under the market-based rates mechanism approved by the Maryland PSC, our actual cost of gas
is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and
customers.

Customers
who do not purchase gas from BGE are not subject to the gas cost adjustment clauses because we are not selling gas to them. However, these customers are charged base rates to
recover the costs BGE incurs to deliver their gas through our distribution system, and are included in the gas distribution volume revenues.

Gas
cost adjustment revenues increased in 2008 compared to 2007 because we sold gas at higher prices, partially offset by less gas sold.

Gas
cost adjustment revenues increased in 2007 compared to 2006 because we sold more gas at higher prices.

Off-System Sales

Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas
sales, which occur after BGE has satisfied its customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system
sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.

Revenues
from off-system gas sales increased in 2008 compared to 2007 because we sold gas at higher prices, partially offset by less gas sold.

Revenues
from off-system gas sales decreased in 2007 compared to 2006 because we sold gas at lower prices, partially offset by more gas sold.

Gas Purchased For Resale Expenses

Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system sales. These costs do
not include the cost of gas purchased by delivery service only customers.

Gas
costs increased $54.7 million in 2008 compared to 2007 because we purchased gas at higher prices, partially offset by lower volumes.

Gas
costs increased $58.3 million in 2007 compared to 2006 because we purchased more gas, partially offset by lower prices.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses increased $12.7 million in 2007 compared to 2006 mostly due to higher labor and benefit
costs and the impact of inflation on other costs of $8.9 million and increased uncollectible accounts receivable expense of $1.2 million.

Gas Workforce Reduction Costs

During the fourth quarter of 2008, we executed a restructuring of the workforce at our operations. We recognized a $1.8 million
pre-tax charge in 2008 related to this reduction in force.

We
incurred no workforce reduction costs in 2007 or 2006.

Gas Depreciation and Amortization

Regulated gas depreciation and amortization expense decreased $3.1 million in 2008 compared to 2007, primarily due to $3.5 million in
lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement
agreement. The Maryland settlement agreement is discussed in more detail inNote 2 to Consolidated Financial Statements.

Gas Taxes Other Than Income Taxes

Gas taxes other than income taxes increased $2.3 million in 2007 compared to 2006, primarily due to increased property taxes.

Other Nonregulated Businesses

Results

2008

2007

2006(In millions)Revenues

$
253.4

$
249.8

$
231.0Operating expenses


(178.2
)

(173.5
)

(173.1
)Merger termination and strategic alternatives costs








(0.5
)Workforce reduction costs


(0.4
)




Depreciation and amortization


(68.2
)

(53.7
)

(37.7
)Taxes other than income taxes


(3.0
)

(2.4
)

(2.0
)Income from Operations

$
3.6

$
20.2

$
17.7Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax)

$
4.7

$
16.5

$
11.3Income from discontinued operations (after-tax)








0.9Net Income

$
4.7

$
16.5

$
12.2Other Items Included In Operations (after-tax):Merger termination and strategic alternatives costs

$


$


$
(0.2
)Workforce reduction costs


(0.3
)




Total Other Items

$
(0.3
)
$


$
(0.2
)


Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3
provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Net income decreased $11.8 million in 2008 compared to 2007 primarily because the first quarter of 2007 included a gain related to a sale
of a leasing arrangement that did not occur in 2008 and due to increased depreciation and amortization of $8.7 million after-tax.

60

---



Table of Contents

Net
income from our other nonregulated businesses increased $4.3 million in 2007 compared to 2006, primarily due to higher construction volume at our energy projects business and
a gain related to a sale of a leasing arrangement, partially offset by increased depreciation and amortization of $9.5 million after-tax.

Consolidated Nonoperating Income and Expenses

Gains on Sale of CEP Equity

Gains on sale of CEP equity decreased $63.3 million for the year ended December 31, 2008 as CEP, an equity investment of Constellation
Energy, did not sell additional equity in 2008 as it had during 2007.

In
November 2006, CEP completed an initial public offering of 5.2 million common units at $21 per unit. As a result of the initial public offering of CEP, we recognized a
pre-tax gain of $28.7 million. As a result of subsequent sales of equity by CEP, which reduced our relative ownership percentage, we recognized pre-tax gains totaling
$63.3 million in 2007. We discuss the issuances of CEP equity in more detail inNote 2 to Consolidated Financial Statements.

Other (Expense) Income

In 2008, we had other expenses of $52.3 million and, in 2007 we had other income of $158.6 million. The $210.9 million decrease
in 2008 compared to 2007 is mostly due to lower interest and investment income as a result of a lower average cash balance of approximately $850 million and an increase in
other-than-temporary impairment charges related to our nuclear decommissioning trust fund assets of $156.5 million.

Other
income at BGE increased $2.8 million in 2008 compared to 2007 primarily due to an increase in equity funds capitalized on increased construction work in progress in 2008.

Other
income increased $92.5 million in 2007 compared to 2006, mostly due to higher interest and investment income due to a higher cash balance.

Total
other income at BGE increased $20.8 million in 2007 compared to 2006, primarily due to carrying charges related to rate stabilization deferrals of "Electricity Purchased for
Resale" expense. We discuss the rate stabilization deferrals in more detail in theRegulated Electric Businesssection.

Fixed Charges

Fixed charges increased $56.7 million in 2008 compared to 2007 mostly due to a higher level of interest expense associated with the new debt
issuances and higher amortization of debt issuance and credit facility costs.

Fixed
charges at BGE increased $14.6 million in 2008 compared to 2007 mostly due to a higher level of interest expense associated with the new debt issuances and higher
amortization of debt issuance and credit facility costs.

Fixed
charges decreased $23.1 million in 2007 compared to 2006, mostly due to a lower average level of debt outstanding.

Fixed
charges at BGE increased $22.7 million in 2007 compared to 2006 mostly due to interest expense recognized on debt that was issued in October 2006 and the rate stabilization
bonds issued in June 2007.

Income Taxes

Our income tax expense decreased $506.6 million during 2008 compared to 2007 mostly due to a decrease in income before income taxes, which
included approximately $1.2 billion of non-tax deductible merger termination and strategic alternatives costs, partially offset by the absence of synthetic fuel tax credits, which
expired in 2007.

BGE's
income tax expense decreased $75.3 million during 2008 compared to 2007 primarily due to lower pre-tax income as a result of the $189 million Maryland
settlement credit recorded in 2008. We discuss the Maryland settlement agreement in more detail inNote 2 to Consolidated Financial Statements.

Our
income taxes increased $77.3 million in 2007 compared to 2006 mostly because of an increase in pre-tax income and a decrease in synthetic fuel tax credits of
$20 million.

In
2007, the State of Maryland increased its corporate income tax rate from 7% to 8.25%, effective January 1, 2008. The impact of adjusting all existing deferred income tax assets
and liabilities for this change in the period of enactment was not material to us. However, this did impact BGE, as discussed below.

Income
taxes at BGE decreased $6.2 million in 2007 compared to 2006, primarily due to lower pre-tax income partially offset by the increase in the Maryland state tax
rate.

Defined Benefit Plans Expense and Funded Status

Our actual return on qualified pension plan assets for the purpose of computing annual net periodic pension cost in accordance with SFAS
No. 87,Employers' Accounting for Pensionswas a loss of 29.5% during 2008 as compared to our assumption of an expected annual return on pension
plan assets of 8.75%. This loss reflects the substantial declines in financial markets experienced through 2008. As disclosed inNote 7 to Consolidated Financial
Statements, we determine the expected return on pension plan assets component of our annual pension expense using a market-related value of pension plan assets that recognizes
asset
gains and losses over a five-year period. As a result of the losses incurred during 2008, our annual pension expense will increase beginning in 2009. Also, the lower fair value of our
pension plan assets increased our unfunded pension obligation at December 31, 2008 and the related after-tax charge to "Accumulated other comprehensive loss" in accordance with SFAS
No. 158,Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans(SFAS No. 158).

In
addition to the losses experienced on our pension plan assets during 2008, there has also been a decrease in the discount rate we use to determine our defined benefit plan
liabilities. At December 31, 2008, our discount rate assumption decreased to 6.00% from 6.25% in the prior year as a result of a decrease in interest rates. This will increase our pension and
postretirement benefits expense beginning in 2009 and resulted in an increase in our unfunded obligation for those plans at December 31, 2008.

We
disclose the SFAS No. 158 funded status adjustment at December 31, 2008, inNote 7 to Consolidated Financial

61

---



Table of Contents

Statements. In addition, effective January 1, 2009, we are reducing our expected annual return on pension plan assets from 8.75% to 8.50% based on updated analyses of
projected future asset returns. As a result of the losses experienced on our qualified pension plan assets during 2008 and the reductions to our expected annual return on pension plan assets and
discount rate assumptions, we expect our annual defined benefit plans cost will be higher by approximately $15 million pre-tax, for the next five years. In connection with the
decline in our qualified pension plan funded status at December 31, 2008, we also expect to increase our annual qualified pension plan contributions from the $76 million we contributed
in 2008 to an average level of approximately $180 million per year over the next five years. These expectations about future cost and funding levels are subject to material revision based on
numerous factors including actual pension asset returns, future interest rate levels, impact of available liquidity on amount and timing of contributions, potential changes in regulatory requirements,
plan design amendments, and demographic experience.

Allowance for Uncollectible Accounts Receivable

Our allowance for uncollectible accounts receivable increased $195.7 million from $44.9 million at December 31,
2007 to $240.6 million at December 31, 2008, related to our merchant energy business and regulated electric and gas businesses.

The
increase in allowance for uncollectible accounts receivable from our merchant energy business was a result of counterparties with financial difficulties. The regulated electric and
gas allowance for uncollectible accounts receivable increased $13.0 million in 2008 compared to 2007, mostly due to increased customer bills caused by higher standard offer service rates and
the decreased ability of customers to pay their utility bills as a result of the economic downturn.

If
the current economic recession continues on a prolonged basis, our and BGE's bad debt expense could increase in the future despite our efforts to mitigate those risks. We discuss our
credit risk in more detail in theRisk Managementsection.

62

---



Table of Contents

Financial Condition

Cash Flows

The following table summarizes our 2008 cash flows by business segment, as well as our consolidated cash flows for 2008, 2007, and
2006.

2008 Segment Cash FlowsHolding Company and Other

Consolidated Cash FlowsMerchant

Regulated

2008

2007

2006(In millions)Operating ActivitiesNet (loss) income

$
(1,357.4
)
$
38.3

$
4.7

$
(1,314.4
)
$
821.5

$
936.4Non-cash merger termination and strategic alternatives costs


541.8








541.8





Other non-cash adjustments to net (loss) income


816.8


334.2


48.4


1,199.4


545.4


223.6Changes in working capitalDerivative assets and liabilities, excluding collateral


(750.5
)

(2.0
)

(5.4
)

(757.9
)

(138.2
)

(286.1
)Net collateral and margin


(962.1
)

1.8





(960.3
)

49.6


(630.6
)Other changes


2.9


(45.0
)

135.7


93.6


(242.4
)

239.0Defined benefit obligations (1)











(20.8
)

(53.6
)

40.5Other


(6.1
)

(35.1
)

(14.5
)

(55.7
)

(54.5
)

2.5Net cash (used in) provided by operating activities


(1,714.6
)

292.2


168.9


(1,274.3
)

927.8


525.3Investing ActivitiesInvestments in property, plant and equipment


(1,425.1
)

(421.5
)

(87.5
)

(1,934.1
)

(1,295.7
)

(962.9
)Asset acquisitions and business combinations, net of cash acquired


(309.8
)




(5.5
)

(315.3
)

(347.5
)

(137.6
)Investment in nuclear decommissioning trust fund securities


(440.6
)







(440.6
)

(659.5
)

(492.5
)Proceeds from nuclear decommissioning trust fund securities


421.9








421.9


650.7


483.7Net proceeds from sale of gas-fired plants and discontinued operations

















1,630.7Issuances of loans receivable














(19.0
)

(65.4
)Sale of investments and other assets


432.3


12.9


1.1


446.3


13.9


43.9Contract and portfolio acquisitions














(474.2
)

(2.3
)Decrease (increase) in restricted funds (2)


(16.6
)

15.5


(941.7
)

(942.8
)

(109.9
)

7.7Other investments


23.2





(1.5
)

21.7


(45.3
)

54.8Net cash (used in) provided by investing activities


(1,314.7
)

(393.1
)

(1,035.1
)

(2,742.9
)

(2,286.5
)

560.1Cash flows from operating activities less cash flows from investing activities

$
(3,029.3
)
$
(100.9
)
$
(866.2
)

(4,017.2
)

(1,358.7
)

1,085.4Financing Activities (1)Net issuance (repayment) of debt (includes $1 billion proceeds from MidAmerican and $1 billion proceeds from EDF)











3,447.7


(33.1
)

242.2Debt issuance costs











(104.8
)




Proceeds from issuance of common stock











17.6


65.1


84.4Common stock dividends paid











(336.3
)

(306.0
)

(264.0
)Reacquisition of common stock











(16.2
)

(409.5
)

Proceeds from initial public offering of CEP

















101.3Proceeds from contract and portfolio acquisitions














847.8


221.3Other











115.5


1.2


5.5Net cash provided by financing activities











3,123.5


165.5


390.7Net (decrease) increase in cash and cash equivalents










$
(893.7
)
$
(1,193.2
)
$
1,476.1


Certain prior-year amounts have been reclassified to conform with the current year's presentation.

63

---



Table of Contents

Cash Flows from Operating Activities

Cash used in operating activities was $1,274.3 million in 2008 compared to cash provided by operating activities of $927.8 million in
2007. This $2,202.1 million decrease in cash flows was primarily due to an increase in net collateral and margin posted, payments to MidAmerican to terminate our planned merger, payments in
connection with the conversion of the Series A Preferred Stock, and credits rebated to BGE residential electric customers.

Total
net cash collateral posted in 2008 increased as follows:

(In millions)Net collateral and margin posted, December 31, 2007

$
(485.3
)Return of collateral held associated with nonderivative contracts


(26.3
)Additional collateral posted associated with nonderivative contracts *


(330.5
)Additional initial and variation margin posted on exchange-traded transactions recorded in accounts receivable


(94.0
)Additional fair value net cash collateral posted (netted against derivative assets / liabilities) **


(509.5
)Change in net collateral and margin posted


(960.3
)Net collateral and margin posted, December 31, 2008

$
(1,445.6
)


The
$960.3 million increase in net collateral and margin posted during 2008 primarily reflects the following:



We
discuss all forms of collateral in terms of their impact on our net available liquidity in theAvailable Sources of Fundingsection.

The
remaining unfavorable change in cash used in operating activities in 2008 compared to 2007 was primarily due to the following:



Cash
provided by operating activities was $927.8 million in 2007 compared to $525.3 million in 2006. This $402.5 million favorable change was primarily due to an
increase in non-cash adjustments to net income and favorable changes in working capital, offset in part by unfavorable changes in net income.

Non-cash
adjustments to net income increased $321.8 million in 2007 compared to 2006, primarily due to the absence of a $191.4 million gain on sale of
gas-fired plants and discontinued operations in 2006, a change in deferred fuel costs of $100.5 million related mostly to lower deferrals of electricity purchased for resale under
the BGE rate stabilization plan, and a $98.2 million increase in deferred income tax expense.

Changes
in working capital had a negative impact of $331.0 million on cash flows from operations in 2007 compared to a negative impact of $677.7 million in 2006. The
improvement in working capital of $346.7 million was mainly due to a $680.2 million change in collateral related to changes in commodity prices and the level of our open positions, and a
$147.9 million favorable change in working capital related to our derivative positions, partially offset by a $481.4 million unfavorable change in other components of working capital.

Cash Flows from Investing Activities

Cash used in investing activities was $2,742.9 million in 2008 compared to $2,286.5 million in 2007. The $456.4 million increase
in cash used in 2008 compared to 2007 was primarily due to:



These
increased uses of cash in investing activities are partially offset by the absence in 2008 of $474.2 million of cash used in 2007 for contract and portfolio acquisitions,
which we discuss in more detail below, and approximately $432.4 million of higher proceeds received from sales of investments in 2008 compared to 2007. The proceeds in 2008 include
$150 million of cash received from EDF that we will record as additional

64

---



Table of Contents

proceeds
for EDF's purchase of 49.99% membership interest in our nuclear generation and operation business.

Cash
used in investing activities was 2,286.5 million in 2007 compared to cash provided by of $560.1 million in 2006. The $2,846.6 million unfavorable change in 2007
compared to 2006 was primarily due to the following:



Cash Flows from Financing Activities

Cash provided by financing activities was $3,123.5 million in 2008 compared to $165.5 million in 2007. The increase of
$2,958.0 million was primarily due to the issuance of:



Cash
provided by financing activities was $165.5 million in 2007 compared to $390.7 million in 2006. The unfavorable change of $225.2 million was primarily due to
cash used for reacquisition of common stock of $409.5 million, a net decrease in cash related to changes in short-term borrowings and long-term debt of
$275.3 million, and a net decrease of $101.3 million in proceeds from the initial public offering of CEP in 2006. This was partially offset by an increase in gross proceeds from contract
and portfolio acquisitions of $626.5 million, which we discuss below.

In
October 2007, our Board of Directors approved a common share repurchase program for up to $1 billion of our outstanding common shares. Subsequent to this approval, on
October 31, 2007, we entered into an accelerated share repurchase agreement with a financial institution, and on November 2, 2007 we purchased 2,023,527 of outstanding shares of our
common stock for $250 million. We did not repurchase any shares under this program during 2008. We discuss the share repurchase program in more detail inNote 9
to Consolidated Financial Statements.

Contract and Portfolio Acquisitions

During 2007 and 2006, our merchant energy business acquired several pre-existing energy purchase and sale agreements, which generated
significant cash flows at the inception of the contracts. These agreements had contract prices that differed from market prices at closing, which resulted in cash payments from the counterparty at the
acquisition of the contract. We received net cash of $373.6 million in 2007 and $219.0 million in 2006 for various contract and portfolio acquisitions. We reflect the underlying
contracts on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether they were above- or below-market prices at closing; therefore, we have also reflected them
on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:

Year ended December 31,

2008

2007

2006(In millions)Financing activitiesproceeds from contract and portfolio acquisitions

$


$
847.8

$
221.3Investing activitiescontract and portfolio acquisitions





(474.2
)

(2.3
)Cash flows from contract and portfolio acquisitions

$


$
373.6

$
219.0


We record the proceeds we receive to acquire energy purchase and sale agreements as a financing cash inflow because it constitutes a prepayment for a portion of
the market price of energy, which we will buy or sell over the term of the agreements and does not represent a cash inflow from current period operating activities. For those acquired contracts that
are derivatives, we record the ongoing cash flows related to the contract with the counterparties as financing cash inflows in accordance with SFAS No. 149. For those acquired contracts that
are not derivatives, we record the ongoing cash flows related to the contract as operating cash flows.

We
discuss certain of these contract and portfolio acquisitions in more detail inNote 5 to Consolidated Financial Statements.

Security Ratings

Independent credit rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies'
assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each company to sell these securities and,
in certain cases, the company's ability to access the markets to sell securities. Generally, the better the rating, the lower the cost of the securities to each company when they sell them. A
reduction in our credit ratings could have an adverse effect on our access to liquidity sources, increase our cost of funds, trigger additional collateral requirements, and/or decrease

65

---



Table of Contents

the
number of investors and counterparties willing to transact with us.

The
factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include, but are not limited to, cash flows, liquidity, business risk
profile, stock price volatility, political, legislative and regulatory risk, interest charges relative to operating cash flow, and the level of debt relative to operating cash flows and to total
capitalization.

At
the date of this report, our credit ratings were as follows:

Standard
& Poors
Rating Group

Moody's
Investors
Service

Fitch-
RatingsConstellation EnergySenior Unsecured Debt

BBB

Baa3

BBBCommercial Paper

A-2

P-3

F2Junior Subordinated Debentures

BB+

Ba1

BBB-BGESenior Unsecured Debt

BBB

Baa2

A-Commercial Paper

A-2

P-2

F2Rate Stabilization Bonds *

AAA

Aaa

AAATrust Preferred Securities

BB+

Baa3

BBB+Preference Stock

BBB

Baa2

BBB+


The ratings in the above table reflect the following outlooks by the credit rating agencies:

Constellation
Energy:



BGE:



We
remain committed to maintaining a stable investment grade credit profile and to meeting our liquidity requirements. We discuss our available sources of funding in more detail below.

We
discuss the potential effect of a ratings downgrade in theAvailable Source of Fundingand Collateralsections.

Available Sources of Funding

In addition to cash generated from business operations, we rely upon access to capital for our capital expenditure programs and for
the liquidity required to operate and support our commercial businesses. Our liquidity requirements are funded by credit facilities and cash. We fund our short-term working capital needs
with existing cash and with our credit facilities, which support direct cash borrowings and the issuance of commercial paper. We also use our credit facilities to support the issuance of letters of
credit, primarily for our merchant energy business.

The
primary drivers of our use of liquidity have been our capital expenditure requirements and collateral requirements associated with hedging our generating assets, hedging our Customer
Supply business in both power and gas, and hedging our coal businesses. Significant changes in the prices of commodities, depending on hedging strategies we have employed, could require us to post
additional letters of credit, and thereby reduce the overall amount available under our credit facilities or to post additional cash, and
thereby reduce our available cash balance. The current disruptions in the credit and capital markets have made it more difficult for us to raise capital and access the credit necessary to obtain
sufficient liquidity to meet our business requirements.

Constellation Energy

At December 31, 2008, we had approximately $6.2 billion in committed credit facilities available as shown below. We have also included
the pro forma effect on our credit facilities, which are reduced or terminated upon the occurrence of certain events, of closing the EDF transactions:

Facility Expiration

Facility
Size

Facility Size
Upon Completion
of the EDF
Transactions(In billions)July 2012

$
3.85

$
2.32November 2009 (A)


1.23


June 2009 (B)


0.60


September 2013


0.35


December 2009


0.15


Total

$
6.18

$
2.32


Collectively,
these facilities currently support the issuance of letters of credit and/or cash borrowings up to $6.2 billion. In late September 2008, we were unable to issue
commercial paper to replace maturing commercial paper and meet other obligations. Instead, we borrowed $485.7 million under one of our credit facilities to secure funds. At December 31,
2008, we had no commercial paper outstanding. During the month of January 2009, Constellation Energy issued no commercial paper. We may utilize commercial paper as a primary source of
short-term debt if market conditions return to normal.

In
connection with the Investment Agreement with EDF, EDF has provided us with up to $2 billion pre-tax, or approximately $1.4 billion after-tax, of
additional liquidity pursuant to a put arrangement that will allow us to require EDF to purchase certain non-nuclear generation assets.

Our
ability to exercise the put arrangement is contingent on certain regulatory approvals that we expect will be received

66

---



Table of Contents

for
all assets covered by the arrangement by April 2009, except for Safe Harbor Water Power Corporation, which is expected by the third quarter of 2009. In addition, exercise of the put option is
conditioned upon third-party consents, the absence of any material liens on such assets, and the absence of a material adverse effect, as defined in the Investment Agreement. The put arrangement will
expire at the earlier of December 31, 2010 or the termination of the Investment Agreement by EDF in the event of a breach of contract by us.

Certain
credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At
December 31, 2008, the debt to capitalization ratios as defined in the credit agreements were no greater than 57%.

Our
$1.23 billion credit facility requires us to maintain consolidated earnings before interest, taxes, depreciation, and amortization to consolidated interest expense ratio of at
least 2.75 when our Standard and Poors senior unsecured debt rating is BBB- or lower and our Moody's senior unsecured debt rating is Baa3 or lower.

The
terms of the Series B Preferred Stock allows us to issue debt without the consent of the holders of the majority of the Series B Preferred Stock only if, after issuance
of such debt, we maintain a ratio of debt to capitalization equal to or less than 65%.

Under
our $3.85 billion and $1.23 billion credit facilities, we will be required to grant a lien on certain generating facilities and pledge our ownership interests in our
nuclear business to the lenders if the Investment Agreement with EDF has closed or been terminated and our Standard & Poors Rating Group or FitchRatings senior unsecured debt credit rating is
below BBB- or our Moody's senior unsecured debt credit rating is below Baa3.

BGE

BGE currently maintains a $400.0 million five-year revolving credit facility expiring in 2011. BGE can use the facility to issue
letters of credit or to issue short-term debt through the issuance of commercial paper or through direct borrowing against the facility. In 2008, in response to the temporary lack of
liquidity in the commercial paper market, BGE drew $370 million on its $400 million credit facility to secure funds in advance of maturing commercial paper and other obligations.

At
December 31, 2008, BGE had no commercial paper outstanding. During the month of January 2009, BGE issued no commercial paper. BGE may utilize commercial paper as a primary
source of short-term debt if market conditions return to normal.

The
credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2008, the debt to
capitalization ratio for BGE as defined in this credit agreement was 55%.

Decreases
in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities.

Net Available Liquidity

The following tables provide a summary of our net available liquidity at December 31, 2008 and 2007:

As of December 31, 2008Constellation
Energy

BGE

Total
Consolidated(In billions)Credit facilities

$
6.2

$
0.4

$
6.6Less: Letters of credit issued


(3.6
)




(3.6
)Less: Cash drawn on credit facilities


(0.5
)

(0.4
)

(0.9
)Undrawn facilities


2.1





2.1Less: Commercial paper outstanding








Net available facilities


2.1





2.1Add: Cash


0.2





0.2Net available liquidity

$
2.3

$


$
2.3


As of December 31, 2007Constellation
Energy

BGE

Total
Consolidated(In billions)Credit facilities

$
4.1

$
0.4

$
4.5Less: Letters of credit issued


(1.8
)




(1.8
)Less: Cash drawn on credit facilities








Undrawn facilities


2.3


0.4


2.7Less: Commercial paper outstanding








Net available facilities


2.3


0.4


2.7Add: Cash


1.1





1.1Net available liquidity

$
3.4

$
0.4

$
3.8


Net available liquidity decreased during 2008 by approximately $1.5 billion as follows:

(In billions)Increase in letters of credit issued

$
(1.8
)Decrease in cash


(0.9
)Increase in cash drawn on credit facilities


(0.9
)Increase in credit facilities


2.1Decrease in net available liquidity

$
(1.5
)


The increase in letters of credit issued and the decrease in cash was primarily due to increased collateral requirements. We discuss our changes in collateral
during 2008 in more detail in theCollateralsection. We discuss the impact of the higher cash collateral posting in the Financial ConditionCash-Flowssection.

67

---



Table of Contents

The
change in credit facilities was due to the following:



The
following table provides our net available liquidity at January 31, 2009:

As of January 31, 2009Constellation
Energy

BGE

Total
Consolidated(In billions)Credit facilities

$
6.2

$
0.4

$
6.6Less: Letters of credit issued


(3.5
)




(3.5
)Less: Cash drawn on credit facilities


(1.2
)

(0.4
)

(1.6
)Undrawn facilities


1.5





1.5Less: Commercial paper outstanding








Net available facilities


1.5





1.5Add: Cash


0.8





0.8Net available liquidity

$
2.3

$


$
2.3


Net available liquidity was unchanged at January 31, 2009 compared to December 31, 2008. However, we executed additional cash draws
from our credit facilities of $0.7 billion primarily due to working capital requirements for our power and natural gas settlements.

As
a result of the significant events of 2008, we have made substantial changes in our strategy to improve our liquidity and our credit profile, including focusing on the following
immediate goals:



Our
liquidity needs vary as commodity prices change. We regularly evaluate the effects of changing price levels on our liquidity needs by estimating the impacts of volatile power, gas,
and coal prices on our price sensitive sources and uses of liquidity. For example, energy contracts settling in the current year may impact our cash flows and changing price levels may impact our
collateral requirements. Additionally, we consider the impact of other sources and uses of liquidity, including planned business divestitures, anticipated new business, capital expenditures, operating
expenses and credit charges. Also, we are exposed to certain operational risks that could have a significant impact on our liquidity. We discuss these risks in more detail in the Risk Factorssection.

We
believe that the actions that we have taken will be sufficient to meet our ongoing liquidity requirements over the next 12 months. However, if we cannot successfully execute on
our strategies and/or actual changes in commodity prices differ from our estimates, our available liquidity would be negatively affected, which would have a material adverse effect on our financial
results and condition.

Collateral

Constellation Energy's collateral requirements arise from its merchant energy business' need to participate in certain organized
markets, such as Independent System Operators (ISOs) or financial exchanges as well as from our goal of remaining economically hedged in our Generation and power and gas Customer Supply operations,
third party coal business, and our trading activities. To support wholesale and retail power Customer Supply obligations, as well as some trading activities, Constellation Energy posts collateral to
ISOs. Forward hedging of our Generation and Customer Supply obligations, as well as our Global Commodities trading activities, creates the need to transact with exchanges such as New York Mercantile
Exchange, Intercontinental Exchange, and NOS Clearing ASA. We post initial margin based on exchange rules, as well as variation margin related to the change in value of the net open position with the
exchange. Constellation Energy's initial margin requirements increased during the third quarter as a result of changes in exchange rules and decreased during the fourth quarter as a result of
portfolio risk reduction and downsizing activities. Daily variation margin postings to each exchange depend on price moves in the underlying power, gas and coal exchange traded forward and option
contracts.

In
addition to the collateral posted to ISOs and exchanges, we post collateral with certain counterparties. These collateral amounts may be fixed or may vary with price levels.

There
are certain asymmetries relating to the use of collateral that create liquidity requirements for our merchant energy businesses. These asymmetries arise as a result of our actions
to be economically hedged as well as market conditions or conventions for conducting business that result in some transactions being collateralized while others are not, including:



68

---



Table of Contents



Constellation
Energy is required to post collateral in the form of either cash or letters of credit. In an environment of stable commodity prices, Constellation Energy's net collateral
position is relatively stable. However, during 2008, the energy markets were affected by large fluctuations in commodity prices as can be seen in the following table summarizing changes in spot prices
during 2008:

Increases (decreases) from December 31, 2007

Six months ended
June 30, 2008

Nine months ended
September 30, 2008

Year ended
December 31, 2008Power


33
%

(8
)%

(30
)%Natural gas


44
%

(5
)%

(30
)%Coal


153
%

58
%

(1
)%Crude oil


55
%

1
%

(40
)%


The price variability in 2008 impacted our posting of cash and letters of credit in 2008 as follows:

Six months ended June 30, 2008

Six months ended December 31, 2008

Year ended December 31, 2008(In millions)Additional (return of) collateral held associated with nonderivative contracts

$
345.5

$
(371.8
)
$
(26.3
)Additional collateral posted associated with nonderivative contracts


(123.9
)

(206.6
)

(330.5
)(Additional) return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable


(428.0
)

334.0


(94.0
)(Additional) return of fair value net cash collateral posted (netted against derivative assets/liabilities)


732.3


(1,241.8
)

(509.5
)Source (use) of cash collateral


525.9


(1,486.2
)

(960.3
)Letters of credit (issued by) returned to us


(2,522.9
)

716.6


(1,806.3
)Total use of collateral

$
(1,997.0
)
$
(769.6
)
$
(2,766.6
)


During the first half of 2008, increasing power prices caused certain hedges of our customer supply load to move deeply in-the-money,
driving up the cash collateral and letters of credit posted by counterparties to us. However, letters of credit posted to us do not affect our liquidity position. At the same time, rising
international coal prices required us to post additional cash and letters of credit to collateralize out-of-the money hedges of our international coal sales. These two impacts
resulted in a net reduction in our use of cash collateral as we received more cash than we posted. However, there was a significant increase in our posting of letters of credit.

During
the second half of the year, our use of collateral postings remained fairly constant despite our fourth quarter portfolio downsizing. Portfolio downsizing led to decreases in the
levels of collateral posted to exchanges to support initial margin requirements, as well as the collateral posted to ISOs. However, as commodity prices have fallen, the hedges of our customer supply
load moved out-of-the money, causing us to post significant amounts of cash collateral to our counterparties. This collateral outflow for power positions was partially offset
by the collateral inflow since June 2008 on our international coal hedges, which have become significantly less out-of-the money as coal prices have fallen.

The
net impact of all of these price changes, as well as the portfolio downsizing has resulted in a net increase in our use of collateral of $2.8 billion for 2008.

We
discuss our use of cash collateral further in theFinancial Conditionsection and we discuss our letters of credit usage further in the Net Available Liquiditysection.

Customers
of our merchant energy business rely on the creditworthiness of Constellation Energy. In this regard, we have certain agreements that contain provisions that would require us
to post additional collateral upon a credit rating downgrade in the senior unsecured debt of Constellation Energy. Based on contractual provisions at December 31, 2008 and January 31,
2009, we estimate that if Constellation Energy's senior unsecured debt were downgraded to one level below the investment grade threshold we would have the following additional collateral obligations:

Credit Ratings Downgraded to *

Level Below
Current Rating

Additional
Obligations(In billions)Below investment grade


1

$
1.8


Based
on market conditions and contractual obligations at the time of a downgrade, we could be required to post additional collateral in an amount that could exceed the obligation
amounts specified above, which could be material. We discuss our credit ratings in theSecurity Ratingssection. We discuss our credit facilities in the Available Sources of
Fundingsection.

69

---



Table of Contents

Capital Resources

Our actual consolidated capital requirements for the years 2006 through 2008, along with the estimated annual amount for 2009, are
shown in the following table.

We
will continue to have cash requirements for:



Capital
requirements for 2009 and 2010 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may
vary from the estimates included in the table below because of a number of factors including:



Our
estimates are also subject to additional factors. Please see theForward Looking Statementsand Item 1A. Risk Factorssections.

2006

2007

2008

2009
(Estimate)(In billions)Nonregulated Capital Requirements:Merchant energy (excludes acquisitions)Generation plants

$
0.3

$
0.2

$
0.6

$
0.4Environmental controls





0.2


0.5


0.3Portfolio acquisitions/investments


0.2


0.5


0.2


0.2Technology/other


0.2


0.2


0.1


0.1Nuclear fuel


0.1


0.1


0.2


0.2Total merchant energy capital requirements


0.8


1.2


1.6


1.2Other nonregulated capital requirements





0.1


0.1


Total nonregulated capital requirements


0.8


1.3


1.7


1.2Regulated Capital Requirements:Regulated electric


0.3


0.3


0.4


0.4Regulated gas


0.1


0.1


0.1


0.1Total regulated capital requirements


0.4


0.4


0.5


0.5Total capital requirements

$
1.2

$
1.7

$
2.2

$
1.7


As of the date of this report, we estimate our 2010 capital requirements will be approximately $1.1 billion. This amount excludes the
capital requirements related to our nuclear generation and operation business that is expected to be deconsolidated in 2009 as a result of the closing of the Investment Agreement with EDF.

Capital Requirements

Merchant Energy Business

Our merchant energy business' capital requirements consist of its continuing requirements, including expenditures for:



Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities,
including projects to improve reliability and support demand response and conservation initiatives.

Funding for Capital Requirements

The current disruptions in the credit and capital markets as well as counterparty concerns about our financial condition have made it
more difficult for us to raise capital and access the credit necessary to provide sufficient liquidity to meet our business requirements. We discuss our available sources of funding and strategy to
improve liquidity in theAvailable Sources of Fundingsection.

Merchant Energy Business

We expect to fund the capital requirements of our merchant energy business with internally generated cash and other available sources. To the extent
that internally generated cash is not sufficient to meet those requirements, we would seek additional funding from the money markets, capital markets and lease markets, subject to credit conditions
and market liquidity, and, if necessary, from drawdowns on credit facilities.

The
projects that our merchant energy business develops typically require substantial capital investment. Many of the qualifying facilities and independent power projects that we have an
interest in are financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is collateralized by interests in the physical assets, major project
contracts and agreements, cash accounts and, in some cases, the ownership interest in that project.

Regulated Electric and Gas

We expect to fund capital expenditures associated with our regulated electric and gas businesses with internally generated cash. To the extent that
internally generated cash is not sufficient to meet those requirements, we would seek additional funding from the money markets, capital markets (including trust preferred securities or preference
stock), subject to credit conditions and market liquidity, and, if necessary, from drawdowns on credit facilities. BGE may also receive equity contributions from time to time from Constellation
Energy. BGE also participates in a cash pool administered by Constellation Energy as discussed inNote 16 to Consolidated Financial Statements.

70

---





Table of Contents

Other Nonregulated Businesses

We expect to fund the capital requirements of our other nonregulated businesses with internally generated cash. To the extent that internally
generated cash is not sufficient to meet those requirements, we would seek additional funding from the money markets, capital markets and lease markets, subject to credit conditions and market
liquidity, and, if necessary, from drawdowns on credit facilities. We may also consider sales of securities and assets, and/or from time to time equity contributions from Constellation Energy.

Contractual Payment Obligations and Committed Amounts

We enter into various agreements that result in contractual payment obligations in connection with our business activities. These
obligations primarily relate to our financing arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support the growth in our
merchant energy business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.

We
detail our contractual payment obligations as of December 31, 2008 in the following table:

Payments2009

2010-
2011

2012-
2013

Thereafter

Total(In millions)Contractual Payment ObligationsLong-term debt: (1)NonregulatedPrincipal

$
2,501.5

$
0.5

$
734.8

$
2,671.2

$
5,908.0Interest


409.1


315.0


258.1


3,009.9


3,992.1Total


2,910.6


315.5


992.9


5,681.1


9,900.1BGEPrincipal


65.0


138.2


639.1


1,422.8


2,265.1Interest


134.5


258.1


231.3


1,336.6


1,960.5Total


199.5


396.3


870.4


2,759.4


4,225.6BGE preference stock











190.0


190.0Operating leases (2)


314.8


469.5


405.4


591.4


1,781.1Purchase obligations: (3)Purchased capacity and energy (4)


588.4


282.2


187.5


227.3


1,285.4Fuel and transportation


1,648.5


1,531.4


718.0


1,292.2


5,190.1Other


269.1


87.8


40.6


29.3


426.8Other noncurrent liabilities:FIN 48 tax liability





26.2


102.4


12.8


141.4Pension benefits (5)


238.7


369.4


385.1





993.2Postretirement and post employment benefits (6)


40.0


91.8


105.6


237.9


475.3Total contractual payment obligations

$
6,209.6

$
3,570.1

$
3,807.9

$
11,021.4

$
24,609.0


Off-Balance Sheet Arrangements

For financing and other business purposes, we utilize certain off-balance sheet arrangements that are not reflected in
our Consolidated Balance Sheets. Such arrangements do not represent a significant part of our activities or a significant ongoing source of financing.

We
use these arrangements when they enable us to obtain financing or execute commercial transactions on favorable terms. As of December 31, 2008, we have no material
off-balance sheet arrangements, including:



At
December 31, 2008, Constellation Energy had a total face amount of $16.4 billion in guarantees outstanding, of which $15.0 billion related to our merchant energy
business. These amounts generally do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to
third parties in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for
obligations under commercial transactions covered by these guarantees was approximately $3 billion at December 31, 2008, which represents the total amount the parent company could be
required to fund based on December 31, 2008 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance
Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

We
discuss our other guarantees inNote 12 to Consolidated Financial Statementsand our significant variable interests in Note 4 to Consolidated Financial
Statements.

71

---



Table of Contents

Risk Management

Introduction

Constellation Energy is exposed to market, credit, operational, and business risks that are fundamental to our business of providing products and
services across the energy value chain.

In
general, the risks in our businesses can be classified as one of the following:



These
risks exist in our business with varying levels of exposure, and are interrelated and cannot be managed in isolation.

Each
of the four risk classifications noted above can be affected by numerous internal and external forces, including:



As
a result of the extent and diversity of the risks the Company faces in its business operations, we analyze risk at transaction, portfolio, business, and enterprise-wide
levels to ensure that material risks are identified and managed effectively. We utilize numerous methods to evaluate and measure risks. In general, we evaluate risks in terms of the impact on our
earnings, liquidity, strategic objectives, credit rating, reputation, and values. We identify and evaluate risks based not only on their probability of occurring and magnitude of impact on the
financial statements, but also with respect to the potential for significant or unexpected shifts in market conditions or rules.

We
recognize the importance of managing risk as a key differentiator in the energy business and view the active and effective management of the risks in our businesses to be of paramount
importance. To foster a culture of risk awareness and management, we employ a risk management framework to identify, assess, monitor, manage, and report risks. Our risk management program is based on
established policies and procedures to manage risks, combined with an extensive system of internal controls. Nevertheless, no system of risk management can cost-effectively eliminate all
risks to which an entity is exposed. Thus, in particular environments, the Company may not be able to mitigate risk exposures to the level desired and may have exposures to certain risk factors that
cannot be mitigated.

As
previously discussed, the collapse of the credit markets and the extreme volatility in energy prices in 2008 significantly impacted Constellation Energy's operating results and
financial condition.

We
reviewed our risk management approach in light of the unprecedented market events of 2008 and their implications for the future, and we are updating and strengthening certain of our
policies, measures, and processes. We are taking active steps to incorporate the lessons learned in 2008 in our existing risk management and control frameworks as well as in the structure and
processes of our risk management organization.

These
steps include enhancing our collateral and liquidity stress testing capabilities as well as our data integrity reviews and systems capabilities and controls. For example, we have
continued our focus on value at risk (VaR) as a measure of market risk and supplemented this measure with economic value at risk (EVaR). We have also continued our practice of utilizing stress tests
and broader position limits based on market liquidity and have enhanced these capabilities throughout 2008.

In
this section, we will review the Company's risk in terms of our:



Risk Governance

As has been our practice, the Audit Committee of the Board of Directors periodically reviews compliance with our risk parameters, limits, and trading
guidelines, and our Board of Directors has established a VaR limit. As discussed below, we have a Risk Management Group (RMG) that is responsible for monitoring the key business risks, enforcing
compliance with risk management policies and risk limits, as well as managing credit risk. The RMG reports to the Chief Risk Officer, who provides regular risk management updates to the Audit
Committee and the Board of Directors.

We
also have a Risk Management Committee (RMC) that is responsible for establishing risk management policies, reviewing procedures for the identification, assessment, measurement, and
management of risks, and monitoring and reporting risk exposures. The RMC meets on a regular basis and is chaired by our Chief Risk Officer, and consists of our Chief Executive Officer, our Chief
Financial Officer, our Vice Chairman, and business unit leaders. In addition, the Chief Risk Officer coordinates with the risk management committees at the business units that meet regularly to
identify, assess, and quantify material risk issues and to develop strategies to manage these risks.

In
an effort to manage market and credit risks, Constellation Energy has established a series of limits that reflect the Company's risk tolerances in the context of the market
environment and our business strategy. In setting limits, the Company takes into consideration factors such as market volatility, product liquidity, business trends, and management experience. The
Company maintains different limits at the corporate and business unit levels. Business units are responsible for adhering to established limits, against which exposures are monitored and reported.
Limit breaches are reported in a timely manner to senior management, who consults with the business

72

---



Table of Contents

unit
on an appropriate course of actionfor instance, reducing trading positions.

Risk Controls

Risk controls are applied at the level of individual exposures and portfolios of exposures in each business and to risk in aggregate, across all
businesses and major risk types, relative to the Company's risk capacity.

Constellation
Energy's RMG is an independent function tasked with providing an independent quantification and assessment of key business risks, as well as providing an evaluation of
individual risk components that contribute to the Company's consolidated risk profile. The RMG is also responsible for establishing risk policies, maintaining appropriate risk controls, ensuring
compliance with policies and procedures, and monitoring methods according to the risk parameters established by the Board of Directors.

The
RMG consists of five divisions that focus on a specialized area of risk.

Wholesale and Retail Credit Risk Management

Wholesale Credit Risk Management establishes guidelines necessary for rating counterparties and assigning limits. This group supports the business
units by establishing credit relationships with various counterparties and facilitating market liquidity with limits and appropriate credit terms and conditions. The Retail Credit Risk Management
group works as a partner with our retail customer-facing operations to manage credit risks associated with our retail supply businesses. This group evaluates credit and manages overall credit exposure
for the retail operation.

Credit
risk managers are responsible for enforcing credit policies, including monitoring, reporting, escalating, and mitigating trade violations and limit exceptions.

Market Risk Management

Market Risk Management is responsible for effectively identifying, monitoring, and reporting on market risk, to include price volatility, market
liquidity, and portfolio risk management. Their key responsibilities are to identify market risk exposures including commodity, interest rate, and foreign exchange risk, and to monitor both physical
and financial
portfolio positions. This group also enforces the Market Risk policies and ensures compliance with these policies, including the monitoring, analyzing, and escalating of market risk controls, such as
exposure limits and price verification results.

Collateral Risk Management

Collateral Risk Management is responsible for providing an integrated view on credit, market, and company liquidity risks to manage the Company's
collateral position. This group's responsibilities include measuring and monitoring collateral outflow, downgrade collateral needs, and collateral use across the Company. Additionally, this group
estimates potential collateral requirements due to market shifts, hedging strategies, and adjustments to the Company's credit ratings. Finally, Collateral Risk Management assists the businesses in
determining the strategic use of collateral and the appropriate cost of collateral for transactions.

Operational Risk Management

Each business area maintains responsibility for operational risk management. A corporate staff oversees implementation of a common framework for
defining, measuring, monitoring, and reporting operational risks.

Risk Infrastructure

Risk Infrastructure supports the risk management divisions and consolidates risk exposures across the businesses and disciplines. This group's
responsibilities include risk and credit systems design and maintenance, risk metric development and calculation, controls structure and enforcement, and risk reporting. In addition, the Risk
Infrastructure Group provides analytical support to the risk functions, validates company models, and verifies liquid and illiquid forward price curves and volatilities. Finally, this group performs
independent risk assessments, due diligence, and risk adjusted valuations of transactions, mergers and acquisitions, and large capital projects.

Risk Exposures

We manage risks across our merchant energy, regulated electric, and regulated gas businesses. We summarize below the risks we manage within each of
our businesses.

Merchant Energy Business

Our merchant energy business is exposed to various risks in the competitive marketplace that may materially impact our financial results and affect
our earnings. These risks include changes in commodity prices, potential imbalances in supply and demand, credit risk and operational risk.

Regulated Electric Business

BGE does not own or operate any electric generating facilities. Therefore, BGE's regulated electric business is exposed to market price risk. To
mitigate this, BGE obtains energy and capacity to provide SOS through a competitive bidding process approved by the Maryland PSC. We discuss SOS and the impact on base rates in more detail in Item 1.
BusinessBaltimore Gas and Electric CompanyElectric Businesssection. As a result of this process, BGE's
exposure to market price risk is limited, and at December 31, 2008, our exposure to commodity price risk for our regulated electric business was not material. However, BGE may enter into
electric futures, options, and swaps to hedge its market price risk if appropriate. We discuss this further inNote 13.

BGE's
regulated electric business is also exposed to wholesale credit risk from its suppliers as well as retail credit risk from its customers. Finally, BGE is subject to operational
risks, including potential impacts from storms and distribution asset failures.

73

---



Table of Contents

Regulated Gas Business

BGE acquires all of its natural gas for delivery to customers from third-party suppliers. Therefore, BGE's regulated gas business is exposed to
market price risk. However, BGE recovers the costs of purchased gas under the market-based rates incentive mechanism approved by the Maryland PSC. Additionally, BGE may enter into gas futures,
options, and swaps to hedge its price risk under our market-based rate incentive mechanism and our off-system gas sales program as appropriate. We discuss this further in Note 13. At
December 31, 2008, our exposure to commodity price risk for our regulated gas business was not material.

BGE's
regulated gas business is also exposed to wholesale credit risk from its suppliers as well as retail credit risk from its customers. Finally, BGE is subject to operational risks,
including potential impacts from storms and distribution asset failures.

Risk Exposure Categories

The various categories of risk exposures that we manage include, but are not limited to, market risk, which includes interest rate risk, security
price risk, and foreign currency risk; credit risk, which includes wholesale and retail; and operational risk. As noted above, these risks may be common to more than one of our businesses. We discuss
each of these primary risk exposure categories separately below.

Market
Risk

We
are exposed to the impact of market fluctuations in the price and transportation costs of power, natural gas, coal, and other commodities. These risks arise from our
ownership and operation of power plants, our customer supply operations, and our origination, risk management, and trading activities. These commodity price risks arise from:



A
number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products.
We use such commodities and products in our merchant energy business, and if we do not hedge the associated financial exposure, this commodity price volatility could affect our earnings. These factors
include:



These
factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the world as a result of regional
differences in:



Additionally,
we have fuel requirements that are subject to future changes in coal, natural gas, uranium, and oil prices. Our power generation facilities purchase fuel under contracts or
in the spot market. Fuel prices may be volatile, and the price that can be obtained from electricity sales may not change at the same rate or in the same direction as changes in fuel costs. This could
have a material adverse impact on our financial results.

As
part of our overall portfolio, we manage the market risk of our merchant energy business, including electricity sales, fuel and energy purchases, emission credits, interest rate and
foreign currency risks, weather risk, and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the
variability in future cash flows from forecasted sales and purchases of energy, including:



The
objectives for entering into such hedges include:



The
portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operational, and other factors.

While
some of the contracts we use to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are
not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We use our

74

---



Table of Contents

best
estimates to determine the fair value of commodity and derivative contracts we hold and sell. These estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is likely that future market prices could vary from those used in recording
derivative assets and liabilities subject to mark-to-market accounting, and such variations could be material.

Power,
gas, coal, and other commodity trading risks involve the potential decline in net income or financial condition due to adverse changes in market prices, whether arising from
customer activities or proprietary positions taken by the Company. Price risk is monitored using VaR and EVaR.

VaR:

We
measure the sensitivity of our mark-to-market energy contracts of our Global Commodities operation to potential changes in market prices using
VaR. VaR is a statistical model designed to predict risk of loss based on historical market price volatility. We calculate VaR using a historical variance/covariance technique that models option
positions using a linear approximation of their value. Additionally, we estimate variances and correlation using historical commodity price changes over the most recent rolling three-month period. Our
VaR calculation includes all of our Global
Commodities operation derivative assets and liabilities subject to mark-to-market accounting, including contracts for energy commodities and derivatives that result in physical
settlement and contracts that require cash settlement.

The
VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and our customer supply
load-serving activities.

The
VaR amounts below represent the potential pre-tax loss in the fair value of our Global Commodities operation derivative assets and liabilities subject to
mark-to-market accounting, including both trading and non-trading activities, over one and ten-day holding periods.

Total Wholesale VaR

For the year ended December 31,

2008

2007(In millions)99% Confidence Level, One-Day Holding PeriodYear end

$
19.7

$
20.4Average


26.1


15.4High


38.0


26.8Low


19.7


8.295% Confidence Level, One-Day Holding PeriodYear end

$
15.0

$
15.5Average


19.9


11.7High


28.9


20.4Low


15.0


6.295% Confidence Level, Ten-Day Holding PeriodYear end

$
47.5

$
49.1Average


62.8


37.0High


91.5


64.6Low


47.5


19.7


The mark-to-market VaR during November and December 2008 was adjusted to eliminate the impact of a change in accounting
treatment of coal positions that are expected to be part of the planned sale of our international commodities operation.

We
experienced higher average VaR for the year ended December 31, 2008 compared to the year ended December 31, 2007, primarily due to a higher number of economic hedges of
accrual positions, increased volatility of commodity market prices, and an increase in our trading activities discussed below. We discuss our mark-to-market results in more
detail in theGlobal Commoditiessection.

The
following table details our VaR for the trading portion of our wholesale marketing and risk management derivative assets and liabilities subject to
mark-to-market accounting over a one-day holding period at a 99% confidence level for 2008 and 2007:

Wholesale Trading VaR

For the year ended December 31,

2008

2007(In millions)Average

$
17.8

$
11.0High


27.9


17.4


Trading VaR was higher during 2008 as compared to 2007 due to increased price volatility and greater amount of risk the Global Commodities operation
group managed during the year.

Our
trading positions can be used to manage the commodity price risk of our customer supply activities and our generation facilities. We also engage in proprietary trading activities,
though, as previously discussed, the Company is pursuing a new business strategy and proprietary trading will be sharply curtailed going forward. Trading activities are managed through daily VaR and
stop loss limits and liquidity guidelines.

75

---



Table of Contents

Due
to the inherent limitations of statistical measures such as VaR and the seasonality of changes in market prices, the VaR calculation may not reflect the full extent of our commodity
price risk exposure. Additionally, because our VaR methodology uses a linear approximation method, actual changes in the value of options in our portfolio resulting from significant price changes may
differ from estimates generated using this methodology. As a result, actual changes in the fair value of derivative assets and liabilities subject to mark-to-market accounting
could differ from the calculated VaR, and such changes could have a material impact on our financial results.

While
VaR reflects the risk of loss under normal market conditions, stress testing captures the Company's exposure to unlikely but plausible events in abnormal markets. We regularly
conduct economic value stress tests for our market activities using multiple scenarios that assume stressed changes in both price level and spreads. Additional scenarios focus on the risks predominant
in individual portions of our business segments and include scenarios that focus on loss of generation, customer demand growth or demand destruction, or a shift in the composition of load serving
customers.

Along
with VaR, stress testing is important in measuring and controlling risk. Stress testing enhances the understanding of the Company's risk profile and loss potential, and stress
losses are monitored against limits. We also use stress testing in approvals of non-standard transactions and for cross-business risk measurement, as well as an input to economic capital
allocation. Stress test results, trends, and explanations are provided each month to the Company's senior management and to the lines of business to help them better measure and manage risks and to
understand event risk-sensitive positions.

EVaR:

Where
VaR is a measure of risk for our mark-to-market portfolios, EVaR is a measure that attempts to estimate the sensitivity of our total portfolio
economic value to changes in market prices. The EVaR measure includes all positions of our merchant business, including Generation, Customer Supply, and Global Commodities
operations. Each business day, the Company undertakes EVaR calculations that include both its trading and its non-trading risks. EVaR for non-trading positions measures the
amount of potential change in the fair values of the exposures related to accrual exposures. EVaR is a one-day measure calculated at a 95% confidence level using a 5 year time
horizon. At December 31, 2008, our EVaR was approximately $136 million, which represents a 31% decline from its level of $195 million in mid-September 2008, when we
started reducing the risk of our Global Commodities portfolio. At January 31, 2009, EVaR has declined further to approximately $90 million. EVaR is a statistical risk measurement model
subject to limitations similar to those of VaR.

Interest
Rate Risk

We
are exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt and certain related
interest rate swaps. We may use derivative instruments to manage our interest rate risks.

In
July 2004, to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps relating to $450.0 million of our long-term debt.
These fair value hedges effectively convert our current fixed-rate debt to a floating-rate instrument tied to the three month London Inter-Bank Offered Rate.
Including the $450.0 million in interest rate swaps, approximately 9% of our long-term debt is floating-rate.

We
discuss our use of derivative instruments to manage our interest rate risk in more detail inNote 13 to Consolidated Financial
Statements.

The
following table provides information about our debt obligations that are sensitive to interest rate changes:

Principal Payments and Interest Rate Detail by Contractual Maturity Date

2009

2010

2011

2012

2013

Thereafter

Total

Fair value at
December 31,
2008(Dollars in millions)Long-term debtVariable-rate debt

$


$


$


$
273.2

$
10.0

$
453.5

$
736.7

$
736.7Average interest rate (A)



%


%


%

3.73
%

1.39
%

1.44
%

2.24
%Fixed-rate debt (B)

$
2,566.5
(C)
$
56.9

$
81.8

$
624.1

$
466.6

$
3,640.5

$
7,436.4

$
6,290.3Average interest rate


9.92
%

5.68
%

5.95
%

6.82
%

6.06
%

6.64
%

7.74
%


76

---



Table of Contents

Security
Price Risk

We
are exposed to price fluctuations in financial markets primarily through our pension plan assets, our nuclear decommissioning trust funds, and trust assets securing
certain executive benefits. We are required by the NRC to maintain externally funded trusts for the costs of decommissioning our nuclear power plants. We discuss our nuclear decommissioning trust
funds in more detail inNote 1 to Consolidated Financial Statements.

A
hypothetical 10% decrease in security prices, excluding our pension plan assets, would result in an approximate $105.2 million reduction in the fair value of our financial
investments that are classified as available-for-sale securities, excluding cash. In 2008, our actual loss on pension plan assets was $364.9 million due to significant
declines in the markets in which plan assets are invested. We describe our funding requirements in more detail in theDefined Benefits Plans and Funded
Statussection. We describe our financial investments in more detail inNote 4 to Consolidated Financial Statements, and
our pension plans inNote 7 to Consolidated Financial Statements.

Foreign
Currency Risk

Our
merchant energy business is exposed to the impact of foreign exchange rate fluctuations. This foreign currency risk arises from our activities in countries where we
transact in currencies other than the U.S. dollar. In 2008, our exposure to foreign currency risk was not material. We manage our exposure to foreign currency exchange rate risk using a comprehensive
foreign currency hedging program. While we cannot predict currency fluctuations, the impact of foreign currency exchange rate risk could be material, although we expect it will be minimal with respect
to the Euro-dollar or British pound as we divest our international commodities operation. We will continue to have limited exposure to the Canadian dollar due to our gas and power
operations.

Credit
Risk

We
are exposed to credit risk through our merchant energy business and BGE's operations. Credit risk is the loss that may result from counterparties' nonperformance and
retail collections. We evaluate the credit risk of our Global Commodities operation and our retail activities separately as discussed below.

Wholesale Credit Risk

We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both
mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized
gains, net of any unrealized losses, where we have a legally enforceable right of setoff. We monitor and manage the credit risk of our Global Commodities operation through credit policies and
procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment
arrangements, and the use of master netting agreements.

As
of December 31, 2008 and 2007, counterparties in the credit portfolio of our Global Commodities operation had the following public credit ratings:

At December 31,

2008

2007RatingInvestment Grade (1)


52
%

44
%Non-Investment Grade


15


7Not Rated


33


49


Our
exposure to "Not Rated" counterparties was $1.5 billion at December 31, 2008 compared to $2.1 billion at December 31, 2007. This decrease was mostly due
to a decrease in our portfolio's credit exposure to natural gas customers, international coal customers, and freight companies that do not have public credit ratings. Although not publicly rated, many
of these counterparties are considered investment grade equivalent based on our internal credit ratings.

We
utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. Based on internal credit
ratings, approximately $883.7 million or 60% of the exposure to unrated counterparties was rated investment grade equivalent at December 31, 2008 and approximately $682.9 million
or 33% was rated investment grade equivalent at December 31, 2007. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal
credit ratings.

At December 31,

2008

2007Investment Grade Equivalent


74
%

62
%Non-Investment Grade Equivalent


26


38


Our total exposure, net of collateral, to counterparties across our entire wholesale portfolio is $4.5 billion as of December 31, 2008. The top ten
counterparties account for approximately 32% of our total exposure. As shown in the table below, no single counterparty concentration comprises more than 10% of the total exposure of the portfolio.

If
a counterparty were to default on its contractual obligations and we were to liquidate transactions with that entity, our potential credit loss would include all forward and
settlement exposure plus any additional costs related to termination and replacement of the positions. This would include contracts accounted for using the mark-to-market,
hedge, and accrual accounting methods, the amount owed or due from settled transactions, less any collateral held from the counterparty. In addition, if a counterparty were to default under an accrual
contract that is currently favorable to us, we may recognize a material adverse impact on our results in the future delivery period to the extent that we are required to replace the contract that is
in default with another contract at current market prices. To reduce our credit risk with

77

---



Table of Contents

counterparties,
we attempt to enter into agreements that allow us to obtain collateral on a contingent basis, seek third-party guarantees of the counterparty's obligation, and enter into netting
agreements that allow us to offset receivables and payables with forward exposure across many transactions.

Our
total exposure of $4.5 billion, net of collateral, includes accrual positions and derivatives. The portion of our wholesale credit risk related to transactions that are
recorded in our Consolidated Balance Sheets, net of collateral, totals approximately $1.7 billion and primarily relates to open energy commodity positions from our Global Commodities operation
that are accounted for using mark-to-market accounting, derivatives that qualify for designation as hedges under SFAS No. 133, as well as amounts owed by wholesale
counterparties for transactions that settled but have not yet been paid.

The
following table highlights the credit quality and exposures related to these activities at December 31, 2008:

Rating

Total
Exposure
Before
Credit
Collateral

Credit
Collateral

Net
Exposure

Number of
Counterparties Greater than 10% of Net Exposure

Net
Exposure of
Counterparties
Greater than 10% of Net Exposure(Dollars in millions)Investment grade

$
1,595

$
382

$
1,213




$
Split rating


7





7





Non-investment grade


255


53


202





Internally ratedinvestment grade


293


60


233





Internally ratednon-investment grade


96


11


85





Total

$
2,246

$
506

$
1,740




$



Due to volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties
could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to
deliver the power our Global Commodities operation had contracted for), we could incur a loss that could have a material impact on our financial results.

If
a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of derivative contracts recorded at fair value,
the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts. In addition, if a counterparty were to default
under an accrual contract that is currently favorable to us, we may recognize a material adverse impact in our results in the future delivery period to the extent that we are required to replace the
contract that is in default with another contract at current market prices. These potential losses would be limited to the extent that the in-the-money amount exceeded any
credit mitigants such as cash, letters of credit, or parental guarantees supporting the counterparty obligation.

We
also enter into various wholesale transactions through ISOs. These ISOs are exposed to counterparty credit risks. Any losses relating to counterparty defaults impacting the ISOs are
allocated to and borne by all other market participants in the ISO. These ISOs have established credit policies and practices to mitigate the exposure of counterparty credit risks. As a market
participant, we continuously assess our exposure to the credit risks of each ISO.

BGE
is exposed to wholesale credit risk of its suppliers for electricity and gas to serve its retail customers. BGE may receive performance assurance collateral to mitigate electricity
suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect
changes in market prices. In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the early termination of a
full-requirements service agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to
replace the supply contract are to be recovered from the defaulting supplier or from customers through rates.

Retail Credit Risk

We are exposed to retail credit risk through our competitive electricity and natural gas supply activities, which serve commercial and industrial
companies, and through BGE's electricity and natural gas distribution operations. Retail credit risk results when customers default on their contractual obligations or fail to pay for service
rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve
customers of our nonregulated retail businesses.

Retail
credit risk is managed through established credit approval policies, monitoring customer exposures, and the use of credit mitigation measures such as letters of credit or
prepayment arrangements. In addition, we have taken steps to augment our credit staff in response to current economic conditions.

Retail
credit quality is dependent on the economy and the ability of our customers to manage through unfavorable economic cycles and other market changes. If the business environment
were to be negatively affected by changes in economic or other market conditions, our retail credit risk may be adversely impacted.

Our
retail credit portfolio is diversified with no significant company or industry concentrations. In 2008, reserve levels have been increased across our retail businesses due to
indicators of deteriorating credit quality and macroeconomic slowdown.

BGE
is subject to retail credit risk associated with both the delivery portion of a customer's bill as well as on the uncollectible expense or credit risk from the gas and/or electric
commodity portion of the bills of those customers to whom BGE sells the gas and electric commodity. Although both BGE's delivery and commodity rates include some level of costs for uncollectible
customer accounts receivable expenses, full recovery is not guaranteed and BGE is exposed to these potential losses and related carrying costs.

78

---



Table of Contents

Operational
Risk

Operational
risk is the risk associated with human error or a failure of our processes and systems, or external factors. We are exposed to many types of operational risks,
including the risk of fraud by employees or outsiders, clerical and record-keeping errors, and computer systems malfunctions. In addition, we may also be subject to disruptions in our operating
systems arising from events that are wholly or partially beyond our control, such as natural disasters, acts of terrorism, and computer viruses, which may give rise to losses in service to customers
and/or monetary losses to us.

We
own and operate a number of power generation facilities, which utilize a diverse mix of fuel sources to include coal, gas, oil, hydro, biomass, and nuclear. We are exposed to risk
resulting from generating plants not being available to produce energy and the risks related to physical delivery of energy to meet our customers' needs. If one or more of our generating facilities is
not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed-price sales commitments through the operation of other more costly
generating facilities or through the purchase of energy in the wholesale market at higher prices. We purchase electricity from generating facilities we do not own. If one or more of those generating
facilities were unable to produce electricity due to operational factors, we may be forced to purchase electricity in the wholesale market at higher prices. This could have a material adverse impact
on our financial results.

Our
nuclear plants produce electricity at a relatively low marginal cost. The Nine Mile Point facility and the Ginna facility sell 90% of their respective output under
unit-contingent power purchase agreements (we have no obligation to provide power if the units are not available) to the previous owners. However, if an unplanned outage were to occur at
Calvert Cliffs during periods when demand was high, we may have to purchase replacement power at potentially higher prices to meet our obligations, which could have a material adverse impact on our
financial results.

We
are exposed to the risk that available sources of supply may differ from the amount of power demanded by our customers under fixed-price load-serving contracts. During
periods of high demand, our power supplies may be insufficient to serve our customers' needs and could require us to purchase additional energy at higher prices. Alternatively, during periods of low
demand, our electricity supplies may exceed our customers' needs and could result in us selling that excess energy at lower prices. Either of those circumstances could have a negative impact on our
financial results.

We
are also exposed to variations in the prices and required volumes of natural gas, oil, and coal we burn at our power plants to generate electricity. Therefore, high commodity prices
increase the impact of generator outages and variable load, but as long as the electricity and fuel prices move in tandem, we have limited exposure to changing commodity prices. During periods of high
demand on our generation assets, our fuel supplies may be insufficient and could require us to procure additional fuel at higher prices. Alternatively, during periods of low demand on our generation
assets, our fuel supplies may exceed our needs, and could result in us selling the excess fuels at lower prices. Either of these circumstances will have a negative impact on our financial results.

---

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The information required by this item with respect to market risk is set forth in Item 7of Part II of this Form 10-K under the headingRisk
Management.

79

---





Table of Contents

Item 8. Financial Statements and Supplementary Data

REPORTS OF MANAGEMENT

Financial Statements

The management of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company (the "Companies") is responsible for the information
and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America
based upon available facts and circumstances and management's best estimates and judgments of known conditions.

PricewaterhouseCoopers LLP,
an independent registered public accounting firm, has audited the financial statements and expressed their opinion on them. They performed their audit
in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The
Audit Committee of the Board of Directors, which consists of four independent Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP
to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.

Management's Report on Internal Control Over Financial ReportingConstellation Energy Group, Inc.

The management of Constellation Energy Group, Inc. (Constellation Energy), under the direction of its principal executive officer and
principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

Constellation
Energy's system of internal control over financial reporting is designed to provide reasonable assurance to Constellation Energy's management and Board of Directors
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of
America.

The
management of Constellation Energy conducted an evaluation of the effectiveness of Constellation Energy's internal control over financial reporting using the framework in Internal ControlIntegrated
Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the
COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurance to management and the Board of Directors regarding
achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that Constellation Energy's internal control over financial reporting
was effective as of December 31, 2008.

PricewaterhouseCoopers LLP,
an independent registered public accounting firm, has audited the effectiveness of Constellation Energy's internal control over financial reporting as
of December 31, 2008, as stated in their report on the next page.

GRAPHIC

GRAPHICMayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer

Jonathan W. Thayer Senior Vice President and Chief Financial Officer


Management's Report on Internal Control Over Financial ReportingBaltimore Gas and Electric Company

The management of Baltimore Gas and Electric Company (BGE), under the direction of its principal executive officer and principal financial officer,
is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

BGE's
system of internal control over financial reporting is designed to provide reasonable assurance to BGE's management and Board of Directors regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

The
management of BGE conducted an evaluation of the effectiveness of BGE's internal control over financial reporting using the framework inInternal
ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the COSO framework, an internal
control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurance to management and the Board of Directors regarding achievement of an entity's
financial reporting objectives. Based upon the evaluation under this framework, management concluded that BGE's internal control over financial reporting was effective as of December 31, 2008.

This
annual report does not include an attestation report of BGE's independent registered public accounting firm regarding internal control over financial reporting. Management's report
was not subject to attestation by BGE's independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit BGE to provide only management's
report in this annual report.

GRAPHIC

GRAPHICKenneth W. DeFontes, Jr. President and Chief Executive Officer

Kevin W. Hadlock Senior Vice President and Chief Financial Officer


80

---



Table of Contents

REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Constellation Energy Group, Inc.

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial
position of Constellation Energy Group, Inc. and its subsidiaries (the Company) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial
statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,
based on criteria established inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8. Our
responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards required that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As
discussed inNote 1to the consolidated financial statements, in 2008 the Company changed its method of accounting for the
measurement of fair value and classifying certain collateral balances. As discussed inNote 1to the consolidated financial statements, in 2007
the Company changed its method of accounting for uncertain tax positions. As discussed inNote 7to the consolidated financial statements, in
2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We
have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Constellation
Energy Group, Inc. and its subsidiaries as of December 31, 2006, 2005, and 2004, and the related consolidated statements of income (loss), cash flows, and common shareholders' equity and
comprehensive income for the years ended December 31, 2005 and 2004 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In
our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy Group, Inc. and its subsidiaries included in the Selected
Financial Data appearing under Item 6 for each of the five years in the period ended December 31, 2008, is fairly stated, in all material respects, in relation to the consolidated
financial statements from which it has been derived.

GRAPHIC

PricewaterhouseCoopers LLP
Baltimore, Maryland
February 27, 2009

81

---



Table of Contents

To Board of Directors and Shareholder of Baltimore Gas and Electric Company

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial
position of Baltimore Gas and Electric Company and its subsidiaries (the Company) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audits of the
financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As
discussed inNote 1to the consolidated financial statements, in 2008 the Company changed its method of accounting for the
measurement of fair value. As discussed inNote 1to the consolidated financial statements, in 2007 the Company changed its method of accounting
for uncertain tax positions.

We
have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Baltimore Gas and
Electric Company and its subsidiaries as of December 31, 2006, 2005 and 2004, and the related consolidated statements of income and cash flows for the years ended December 31, 2005 and
2004 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and
Summary of Financial Condition of Baltimore Gas and Electric Company and its subsidiaries included in the Selected Financial Data appearing under Item 6 for each of the five years in the period
ended December 31, 2008, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.

GRAPHIC

PricewaterhouseCoopers LLP
Baltimore, Maryland
February 27, 2009

82

---



Table of Contents

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

2008

2007

2006(In millions, except per share amounts)RevenuesNonregulated revenues

$
16,134.0

$
17,794.6

$
16,279.0Regulated electric revenues


2,679.5


2,455.6


2,115.9Regulated gas revenues


1,004.8


943.0


890.0Total revenues


19,818.3


21,193.2


19,284.9ExpensesFuel and purchased energy expenses


15,521.3


16,473.9


14,930.7Operating expenses


2,378.8


2,447.4


2,165.8Merger termination and strategic alternatives costs


1,204.4





18.3Impairment losses and other costs


741.8


20.2


Workforce reduction costs


22.2


2.3


28.2Depreciation, depletion, and amortization


583.2


557.8


523.9Accretion of asset retirement obligations


68.4


68.3


67.6Taxes other than income taxes


301.8


288.9


290.7Total expenses


20,821.9


19,858.8


18,025.2Net Gain on Sales of Upstream Gas Assets


25.5





Gain on Sale of Gas-Fired Plants








73.8(Loss) Income from Operations


(978.1
)

1,334.4


1,333.5Gain on Sales of CEP LLC Equity





63.3


28.7Other (Expense) Income


(52.3
)

158.6


66.1Fixed ChargesInterest expense


399.1


311.8


329.2Interest capitalized and allowance for borrowed funds used during construction


(50.0
)

(19.4
)

(13.7
)BGE preference stock dividends


13.2


13.2


13.2Total fixed charges


362.3


305.6


328.7(Loss) Income from Continuing Operations Before Income Taxes


(1,392.7
)

1,250.7


1,099.6Income Tax (Benefit) Expense


(78.3
)

428.3


351.0(Loss) Income from Continuing Operations


(1,314.4
)

822.4


748.6(Loss) Income from discontinued operations, net of income taxes of $1.5, and $107.7, respectively





(0.9
)

187.8Net (Loss) Income

$
(1,314.4
)
$
821.5

$
936.4(Loss) Earnings Applicable to Common Stock

$
(1,314.4
)
$
821.5

$
936.4Average Shares of Common Stock OutstandingBasic


179.1


180.2


179.4Average Shares of Common Stock OutstandingDiluted


179.1


182.5


181.4(Loss) Earnings Per Common Share from Continuing OperationsBasic

$
(7.34
)
$
4.56

$
4.17(Loss) Income from discontinued operations





(0.01
)

1.05(Loss) Earnings Per Common ShareBasic

$
(7.34
)
$
4.55

$
5.22(Loss) Earnings Per Common Share from Continuing OperationsDiluted

$
(7.34
)
$
4.51

$
4.12(Loss) Income from discontinued operations





(0.01
)

1.04(Loss) Earnings Per Common ShareDiluted

$
(7.34
)
$
4.50

$
5.16Dividends Declared Per Common Share

$
1.91

$
1.74

$
1.51


See Notes to Consolidated Financial Statements.

83

---



Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

2008

2007(In millions)AssetsCurrent AssetsCash and cash equivalents

$
202.2

$
1,095.9Accounts receivable (net of allowance for uncollectibles of$240.6and $44.9, respectively)


3,389.9


4,289.5Fuel stocks


717.9


591.3Materials and supplies


224.5


207.5Derivative assets


1,465.0


760.6Unamortized energy contract assets


81.3


32.0Restricted cash


1,030.5


41.9Deferred income taxes


268.0


300.7Other


815.5


366.2Total current assets


8,194.8


7,685.6Investments and Other Noncurrent AssetsNuclear decommissioning trust funds


1,006.3


1,330.8Other investments


421.0


542.2Regulatory assets (net)


494.7


576.2Goodwill


4.6


261.3Derivative assets


851.8


1,030.2Unamortized energy contract assets


173.1


178.3Other


421.3


370.6Total investments and other noncurrent assets


3,372.8


4,289.6Property, Plant and EquipmentNonregulated property, plant and equipment


8,866.2


8,087.0Regulated property, plant and equipment


6,419.4


6,051.2Nuclear fuel (net of amortization)


443.0


374.3Accumulated depreciation


(5,012.1
)

(4,745.4
)Net property, plant and equipment


10,716.5


9,767.1Total Assets

$
22,284.1

$
21,742.3


See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.

84

---



Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

2008

2007(In millions)Liabilities and EquityCurrent LiabilitiesShort-term borrowings

$
855.7

$
14.0Current portion of long-term debt


2,591.5


380.6Accounts payable and accrued liabilities


2,370.1


2,630.1Customer deposits and collateral


120.3


146.6Derivative liabilities


1,241.8


1,134.3Unamortized energy contract liabilities


393.5


392.2Accrued expenses


373.1


528.5Other


514.2


427.5Total current liabilities


8,460.2


5,653.8Deferred Credits and Other Noncurrent LiabilitiesDeferred income taxes


677.0


1,588.5Asset retirement obligations


987.3


917.6Derivative liabilities


1,115.0


1,118.9Unamortized energy contract liabilities


906.4


1,218.6Defined benefit obligations


1,354.3


828.6Deferred investment tax credits


44.1


50.5Other


249.6


155.9Total deferred credits and other noncurrent liabilities


5,333.7


5,878.6CapitalizationLong-term debt


5,098.7


4,660.5Minority interests


20.1


19.2BGE preference stock not subject to mandatory redemption


190.0


190.0Common shareholders' equity


3,181.4


5,340.2Total capitalization


8,490.2


10,209.9Commitments, Guarantees, and Contingencies (see Note 12)Total Liabilities and Equity

$
22,284.1

$
21,742.3


See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.

85

---



Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

2008

2007

2006(In millions)Cash Flows From Operating ActivitiesNet (loss) income

$
(1,314.4
)
$
821.5

$
936.4Adjustments to reconcile to net cash provided by operating activitiesGain on sales of gas-fired plants and discontinued operations








(191.4
)Depreciation, depletion, and amortization


583.2


557.8


523.9Amortization of nuclear fuel


123.9


114.3


99.5Amortization of energy contracts


(256.3
)

(222.9
)

(105.2
)All other amortization


40.5


11.2


26.9Accretion of asset retirement obligations


68.4


68.3


67.6Deferred income taxes


(122.8
)

226.2


128.0Investment tax credit adjustments


(6.4
)

(6.7
)

(6.9
)Deferred fuel costs


52.0


(248.0
)

(348.5
)Defined benefit obligation expense


99.6


111.8


129.7Defined benefit obligation payments


(120.4
)

(165.4
)

(89.2
)Merger termination and strategic alternatives costs


541.8





Workforce reduction costs


22.2


2.3


28.2Impairment losses and other costs


741.8


20.2


Impairment losses on nuclear decommissioning trust assets


165.0


8.5


Gains on sale of CEP LLC equity





(63.3
)

(28.7
)Gains on sales of assets and investments


(38.1
)




Gains on termination of contracts


(73.1
)




Equity in earnings of affiliates less than dividends received


6.3


45.3


27.6Derivative power sales contracts classified as financing activities under SFAS No. 149


(107.2
)

32.2


2.6Changes in working capitalAccounts receivable, excluding margin


606.7


(664.2
)

(237.7
)Derivative assets and liabilities, excluding collateral


(757.9
)

(138.2
)

(286.1
)Net collateral and margin


(960.3
)

49.6


(630.6
)Materials, supplies, and fuel stocks


(33.5
)

(66.4
)

(267.2
)Other current assets


(95.4
)

(18.5
)

343.5Accounts payable and accrued liabilities


(225.8
)

448.8


380.5Liability for unrecognized tax benefits


79.7


71.9


Other current liabilities


(238.1
)

(14.0
)

19.9Other


(55.7
)

(54.5
)

2.5Net cash (used in) provided by operating activities


(1,274.3
)

927.8


525.3Cash Flows From Investing ActivitiesInvestments in property, plant and equipment


(1,934.1
)

(1,295.7
)

(962.9
)Asset acquisitions and business combinations, net of cash acquired


(315.3
)

(347.5
)

(137.6
)Investments in nuclear decommissioning trust fund securities


(440.6
)

(659.5
)

(492.5
)Proceeds from nuclear decommissioning trust fund securities


421.9


650.7


483.7Net proceeds from sale of gas-fired plants and discontinued operations








1,630.7Issuances of loans receivable





(19.0
)

(65.4
)Proceeds from sales of investments and other assets


446.3


13.9


43.9Contract and portfolio acquisitions





(474.2
)

(2.3
)(Increase) decrease in restricted funds


(942.8
)

(109.9
)

7.7Other


21.7


(45.3
)

54.8Net cash (used in) provided by investing activities


(2,742.9
)

(2,286.5
)

560.1Cash Flows From Financing ActivitiesNet issuance (maturity) of short-term borrowings


813.7


14.0


(0.7
)Proceeds from issuance of common stock


17.6


65.1


84.4Proceeds from issuance of long-term debt


3,211.4


698.2


852.0Proceeds from initial public offering of CEP








101.3Common stock dividends paid


(336.3
)

(306.0
)

(264.0
)Reacquisition of common stock


(16.2
)

(409.5
)

Proceeds from contract and portfolio acquisitions





847.8


221.3Repayment of long-term debt


(577.4
)

(745.3
)

(609.1
)Derivative power sales contracts classified as financing activities under SFAS No. 149


107.2


(32.2
)

(2.6
)Debt financing costs


(104.8
)




Other


8.3


33.4


8.1Net cash provided by financing activities


3,123.5


165.5


390.7Net (Decrease) Increase in Cash and Cash Equivalents


(893.7
)

(1,193.2
)

1,476.1Cash and Cash Equivalents at Beginning of Year


1,095.9


2,289.1


813.0Cash and Cash Equivalents at End of Year

$
202.2

$
1,095.9

$
2,289.1Other Cash Flow Information:Cash paid during the year for:Interest (net of amounts capitalized)

$
341.4

$
291.8

$
304.7Income taxes

$
119.2

$
282.4

$
109.3


See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.

86

---



Table of Contents

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME

Constellation Energy Group, Inc. and Subsidiaries

Accumulated
Other
Comprehensive
LossCommon Stock

Retained
Earnings

Total
AmountYear Ended December 31, 2008, 2007, and 2006

Shares

Amount(Dollar amounts in millions, number of shares in thousands)Balance at December 31, 2005


178,301

$
2,620.8

$
2,810.2

$
(515.5
)
$
4,915.5Comprehensive IncomeNet income








936.4





936.4Other comprehensive incomeHedging instruments:Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $375.6











620.8


620.8Net unrealized loss on hedging instruments, net of taxes of $1,025.8











(1,683.4
)

(1,683.4
)Available-for-sale securities:Reclassification of net gains on securities from OCI to net income, net of taxes of $0.1











(0.2
)

(0.2
)Net unrealized gain on securities, net of taxes of $45.5











69.7


69.7Minimum pension liability, net of taxes of $49.6











75.6


75.6Net unrealized loss on foreign currency translation











(1.1
)

(1.1
)Total Comprehensive Income








936.4


(918.6
)

17.8Effect of adoption of SFAS No. 158, net of taxes of $111.3











(169.5
)

(169.5
)Common stock dividend declared ($1.51 per share)








(272.6
)




(272.6
)Common stock issued and share-based awards


2,218


117.8








117.8Other








0.3





0.3Balance at December 31, 2006


180,519


2,738.6


3,474.3


(1,603.6
)

4,609.3Comprehensive IncomeNet income








821.5





821.5Other comprehensive incomeHedging instruments:Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $682.3











1,124.8


1,124.8Net unrealized loss on hedging instruments, net of taxes of $408.2











(671.1
)

(671.1
)Available-for-sale securities:Reclassification of net gains on securities from OCI to net income, net of taxes of $1.0











(1.6
)

(1.6
)Net unrealized gain on securities, net of taxes of $25.5











26.5


26.5Defined benefit plans:Net gain arising during period, net of taxes of $7.8











11.6


11.6Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $15.9











24.6


24.6Net unrealized gain on foreign currency translation, net of taxes of $1.8











7.0


7.0Other











(10.8
)

(10.8
)Total Comprehensive Income








821.5


511.0


1,332.5Effect of adoption of FIN 48








(7.3
)




(7.3
)Common stock dividend declared ($1.74 per share)








(368.4
)




(368.4
)Common stock issued and share-based awards


1,789


184.2








184.2Common stock purchased


(1,847
)

(159.5
)







(159.5
)Common stock purchased and retired


(2,024
)

(250.0
)







(250.0
)Other








(0.6
)




(0.6
)Balance at December 31, 2007


178,437


2,513.3


3,919.5


(1,092.6
)

5,340.2Comprehensive LossNet loss








(1,314.4
)




(1,314.4
)Other comprehensive lossHedging instruments:Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $120.2











200.6


200.6Net unrealized loss on hedging instruments, net of taxes of $561.6











(875.3
)

(875.3
)Available-for-sale securities:Reclassification of net losses on securities from OCI to net income, net of taxes of $79.1











81.7


81.7Net unrealized losses on securities, net of taxes of $189.8











(197.5
)

(197.5
)Defined benefit plans:Prior service cost arising during period, net of taxes of $4.9











(7.2
)

(7.2
)Net loss arising during period, net of taxes of $229.2











(339.9
)

(339.9
)Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $14.9











21.3


21.3Net unrealized loss on foreign currency translation, net of taxes of $0.1











(3.1
)

(3.1
)Other











0.2


0.2Total Comprehensive Loss








(1,314.4
)

(1,119.2
)

(2,433.6
)Effect of adoption of SFAS No. 157








0.9





0.9Common stock dividend declared ($1.91 per share)








(341.3
)




(341.3
)Common stock issued and share-based awards *


21,406


667.3


(35.8
)




631.5Common stock purchased


(200
)

(16.1
)







(16.1
)Common stock purchased and retired


(514
)

Other








(0.2
)




(0.2
)Balance at December 31, 2008


199,129

$
3,164.5

$
2,228.7

$
(2,211.8
)
$
3,181.4


* Includes 19,897.3 million shares issued to MidAmerican Energy Holdings Company. See Note 9 for more detail.
See Notes to Consolidated Financial Statements.

87

---



Table of Contents

CONSOLIDATED STATEMENTS OF INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

2008

2007

2006(In millions)RevenuesElectric revenues

$
2,679.7

$
2,455.7

$
2,115.9Gas revenues


1,024.0


962.8


899.5Total revenues


3,703.7


3,418.5


3,015.4ExpensesOperating expensesElectricity purchased for resale


1,880.1


1,500.4


1,167.8Gas purchased for resale


694.5


639.8


581.5Operations and maintenance


537.8


533.6


496.1Workforce reduction costs


6.4





Merger termination and strategic alternatives costs








4.7Depreciation and amortization


227.9


234.2


227.5Taxes other than income taxes


174.5


176.2


168.7Total expenses


3,521.2


3,084.2


2,646.3Income from Operations


182.5


334.3


369.1Other Income


29.6


26.8


6.0Fixed ChargesInterest expense


144.2


127.9


104.6Allowance for borrowed funds used during construction


(4.3
)

(2.6
)

(2.0
)Total fixed charges


139.9


125.3


102.6Income Before Income Taxes


72.2


235.8


272.5Income TaxesCurrent


(18.2
)

(2.4
)

(22.8
)Deferred


40.2


100.0


126.6Investment tax credit adjustments


(1.3
)

(1.6
)

(1.6
)Total income taxes


20.7


96.0


102.2Net Income


51.5


139.8


170.3Preference Stock Dividends


13.2


13.2


13.2Earnings Applicable to Common Stock

$
38.3

$
126.6

$
157.1


See Notes to Consolidated Financial Statements.

88

---



Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,

2008

2007(In millions)AssetsCurrent AssetsCash and cash equivalents

$
10.7

$
17.6Accounts receivable (net of allowance for uncollectibles of$33.3and $20.3, respectively)


327.0


316.7Accounts receivable, unbilled (net of allowance for uncollectibles of$0.9and $0.8, respectively)


232.3


209.5Investment in cash pool, affiliated company


148.8


78.4Accounts receivable, affiliated companies


4.3


4.2Fuel stocks


143.7


98.8Materials and supplies


38.4


42.7Prepaid taxes other than income taxes


51.0


49.9Regulatory assets (net)


79.7


74.9Restricted cash


23.7


39.2Other


10.8


7.4Total current assets


1,070.4


939.3Investments and Other AssetsRegulatory assets (net)


494.7


576.2Receivable, affiliated company


161.1


149.2Other


131.6


148.1Total investments and other assets


787.4


873.5Utility PlantPlant in serviceElectric


4,493.7


4,244.4Gas


1,221.1


1,181.7Common


476.3


456.1Total plant in service


6,191.1


5,882.2Accumulated depreciation


(2,191.0
)

(2,080.8
)Net plant in service


4,000.1


3,801.4Construction work in progress


225.7


166.4Plant held for future use


2.6


2.4Net utility plant


4,228.4


3,970.2Total Assets

$
6,086.2

$
5,783.0


See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

89

---



Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,

2008

2007(In millions)Liabilities and EquityCurrent LiabilitiesShort-term borrowings

$
370.0

$
Current portion of long-term debt


90.0


375.0Accounts payable and accrued liabilities


231.0


182.4Accounts payable and accrued liabilities, affiliated companies


97.0


164.5Customer deposits and collateral


72.3


70.5Current portion of deferred income taxes


40.2


44.1Accrued taxes


18.8


34.4Accrued expenses and other


98.4


96.3Total current liabilities


1,017.7


967.2Deferred Credits and Other LiabilitiesDeferred income taxes


843.3


785.6Payable, affiliated company


243.2


243.7Deferred investment tax credits


10.6


11.9Other


28.6


33.6Total deferred credits and other liabilities


1,125.7


1,074.8Long-term DebtRate stabilization bonds


564.4


623.2First refunding mortgage bonds of BGE





119.7Other long-term debt of BGE


1,443.0


1,214.56.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred
securities


257.7


257.7Long-term debt of nonregulated business


25.0


25.0Unamortized discount and premium


(2.4
)

(2.6
)Current portion of long-term debt


(90.0
)

(375.0
)Total long-term debt


2,197.7


1,862.5Minority Interest


16.9


16.8Preference Stock Not Subject to Mandatory Redemption


190.0


190.0Common Shareholder's EquityCommon stock


912.2


912.2Retained earnings


625.4


758.8Accumulated other comprehensive income


0.6


0.7Total common shareholder's equity


1,538.2


1,671.7Commitments, Guarantees, and Contingencies (see Note 12)Total Liabilities and Equity

$
6,086.2

$
5,783.0


See Notes to Consolidated Financial Statements.

90

---



Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

2008

2007

2006(In millions)Cash Flows From Operating ActivitiesNet income

$
51.5

$
139.8

$
170.3Adjustments to reconcile to net cash provided by operating activitiesDepreciation and amortization


227.9


234.2


227.5Other amortization


13.2


12.5


13.6Deferred income taxes


40.2


100.0


126.6Investment tax credit adjustments


(1.3
)

(1.6
)

(1.7
)Deferred fuel costs


52.0


(248.0
)

(348.5
)Defined benefit plan expenses


30.6


39.8


47.2Allowance for equity funds used during construction


(8.0
)

(4.9
)

(3.7
)Workforce reduction costs


6.4





Changes inAccounts receivable


(33.1
)

(181.5
)

135.8Receivables, affiliated companies


(0.1
)

(1.7
)

(0.7
)Materials, supplies, and fuel stocks


(40.6
)

9.6


(8.2
)Other current assets


(4.5
)

25.9


(31.0
)Accounts payable and accrued liabilities


48.6


(4.9
)

17.6Accounts payable and accrued liabilities, affiliated companies


(67.5
)

1.1


10.6Other current liabilities


(11.4
)

29.6


(0.9
)Long-term receivables and payables, affiliated companies


(45.7
)

(42.0
)

(70.1
)Other


(29.1
)

(44.7
)

(27.5
)Net cash provided by operating activities


229.1


63.2


256.9Cash Flows From Investing ActivitiesUtility construction expenditures (excluding equity portion of allowance for funds used during construction)


(426.4
)

(376.4
)

(320.6
)Change in cash pool at parent


(70.4
)

(17.8
)

(63.8
)Sales of investments and other assets


12.9


0.8


(0.4
)Decrease (increase) in restricted funds


15.5


(42.3
)

10.3Net cash used in investing activities


(468.4
)

(435.7
)

(374.5
)Cash Flows From Financing ActivitiesProceeds from issuance of short-term borrowings


370.0





Proceeds from issuance of long-term debt


400.0


623.2


700.0Repayment of long-term debt


(350.0
)

(124.8
)

(445.3
)Debt issuance costs


(2.7
)




Preference stock dividends paid


(13.2
)

(13.2
)

(13.2
)Distribution to parent


(171.7
)

(106.0
)

(128.1
)Net cash provided by financing activities


232.4


379.2


113.4Net (Decrease) Increase in Cash and Cash Equivalents


(6.9
)

6.7


(4.2
)Cash and Cash Equivalents at Beginning of Year


17.6


10.9


15.1Cash and Cash Equivalents at End of Year

$
10.7

$
17.6

$
10.9Other Cash Flow Information:Cash paid (received) during the year for:Interest (net of amounts capitalized)

$
126.6

$
126.3

$
87.2Income taxes

$
(5.1
)
$
(37.6
)
$
18.7


See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

91

---



Table of Contents

Notes to Consolidated Financial Statements

1Significant Accounting Policies

Nature of Our Business

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various
subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). Our merchant energy business is a competitive provider of energy solutions for a variety of customers.
BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of
ten counties in central Maryland. We describe our operating segments inNote 3.

This
report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries. References in this report
to the "regulated business(es)" are to BGE.

Consolidation Policy

We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity
method, and the cost method.

Consolidation

We use consolidation for two types of entities:



Consolidation
means that we combine the accounts of these entities with our accounts. Therefore, our consolidated financial statements include our accounts, the accounts of our
majority-owned subsidiaries that are not VIEs, and the accounts of VIEs for which we are the primary beneficiary. We have consolidated two VIEs for which we are the primary beneficiary. We eliminate
all intercompany balances and transactions when we consolidate these accounts.

The Equity Method

We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including qualifying
facilities and power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report:



The
only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use
consolidation.

The Cost Method

We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost
in our Consolidated Balance Sheets. We recognize income only to the extent that we receive dividends or distributions. The only time we do not use this method is when we can exercise significant
influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.

Sale of Subsidiary Stock

We may sell portions of our ownership interests through public offerings of a subsidiary's stock. Through 2008, we recorded any gains or losses on
public offerings in our Consolidated Statements of Income (Loss), as a component of non-operating income. Beginning in 2009, we will apply the provisions of SFAS No. 160, Noncontrolling Interests in Consolidated Financial
Statements, an amendment of ARB No. 51.We discuss SFAS No. 160 in further detail later
in this Note.

Regulation of Electric and Gas Business

The Maryland Public Service Commission (Maryland PSC) and the Federal Energy Regulatory Commission (FERC) provide the final
determination of the rates we charge our customers for our regulated businesses. Generally, we follow the same accounting policies and practices used by nonregulated companies for financial reporting
under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or the FERC orders an accounting treatment different from that used by nonregulated
companies to determine the rates we charge our customers.

When
this happens, we and BGE must defer (include as an asset or liability in the Consolidated Balance Sheets and exclude from Consolidated Statements of Income (Loss)) certain regulated
business expenses and income as regulatory assets and liabilities. We and BGE have recorded these regulatory assets and liabilities in the Consolidated Balance Sheets in accordance with Statement of
Financial Accounting Standards (SFAS) No. 71,Accounting for the Effects of Certain Types of Regulation.

We
summarize and discuss regulatory assets and liabilities further inNote 6.

Use of Accounting Estimates

Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the
United States of America. These estimates and assumptions affect various matters, including:



92

---



Table of Contents



These
estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management's control. As a result, actual amounts could materially differ
from these estimates.

Reclassifications

We have reclassified certain prior-year amounts for comparative purposes for the following:



Revenues

Sources of Revenue

We
earn revenues from the following primary business activities:



We
report BGE's revenues from standard offer service and delivery of electricity and natural gas to its customers as "Regulated electric revenues" and "Regulated gas revenues" in our
Consolidated Statements of Income (Loss). We report all other revenues as "Nonregulated revenues."

Revenues
from nonregulated activities result from contracts or other sales that generally reflect market prices in effect at the time that we executed the contract or the sale occurred.
BGE's revenues from regulated activities reflect provisions of orders of the Maryland PSC and the FERC. In certain cases, these orders require BGE to defer the difference between certain portions of
its actual costs and the amount presently billable to customers. BGE records these differences as regulatory assets or liabilities, which we discuss in more detail in Note 6. We describe the
effects of these orders on BGE's revenues below.

Regulated Electric

BGE provides market-based standard offer electric service to residential and small commercial customers for the indefinite future and for large
commercial and industrial customers for varying periods beyond June 30, 2004, depending on customer load. BGE charges these customers standard offer service (SOS) rates that are designed to
recover BGE's wholesale power supply costs and include an administrative fee consisting of a shareholder return component and an incremental cost component. Pursuant to Senate Bill 1, the energy
legislation enacted in Maryland in June 2006, BGE suspended collection of the shareholder return component of the administrative fee for residential SOS service beginning January 1, 2007 for a
10-year period. However, under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, BGE reinstated collection of the residential return component of the SOS
administration charge and began providing all residential electric customers a credit for the return component of the administrative charge. As part of the 2008 Maryland settlement agreement,
which is discussed in more detail inNote 2, BGE resumed collection of the shareholder return portion of the residential standard offer service
administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to all residential electric customers. BGE will cease collecting the residential shareholder
return component again from June 1, 2010 through December 31, 2016. Senate Bill 1 imposed a 15% rate cap for BGE residential electric customers from July 1, 2006 until
May 31, 2007 and gave customers the option to further delay paying full market rates until January 1, 2008.

BGE
defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge portion of SOS rates in a
given period. BGE either bills or refunds its customers the difference in the future.

Regulated Gas

BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses." Under these clauses, BGE defers the
difference between certain of its actual costs related to the gas commodity and what it collects from customers under the commodity charge in a given period for evaluation under a market-based rates
incentive mechanism. For each period subject to that mechanism, BGE compares its actual cost of gas to a market index (a measure of the market price of gas for that period) and shares the difference
equally between shareholders and customers through an adjustment to the price of gas service in future periods. This sharing mechanism excludes fixed-price contracts which the Maryland PSC requires
BGE to procure for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period.

93

---



Table of Contents

Selection
of Accounting Treatment

We
determine the appropriate accounting treatment for recognizing revenues based on the nature of the transaction, governing accounting standards and, where required, by
applying judgment as to the most transparent presentation of the economics of the underlying transactions. We utilize two primary accounting treatments to recognize and report revenues in our results
of operations:



We
describe each of these accounting treatments below.

Accrual Accounting

Under accrual accounting, we record revenues in the period when we deliver energy commodities or products, render services, or settle contracts. We
generally use accrual accounting to recognize revenues for our sales of electricity, gas, coal, and other commodities as part of our physical delivery activities. We enter into these sales
transactions using a variety of instruments, including non-derivative agreements, derivatives that qualify for and are designated as normal purchases and normal sales (NPNS) of commodities
that will be physically delivered, sales to BGE's customers under regulated service tariffs, and spot-market sales, including settlements with independent system operators. We discuss the
NPNS election later in this Note underDerivatives and Hedging Activities.

However,
we also use mark-to-market accounting rather than accrual accounting for recognizing revenue on our nonregulated retail gas customer supply activities
and other physical commodity derivatives if we have not designated those contracts as NPNS.

We
record accrual revenues from sales of products or services on a gross basis at the contract, tariff, or spot price because we are a principal to the transaction and otherwise meet the
requirements of Emerging Issues Task Force (EITF) 03-11,Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes,and EITF 99-19,Reporting Revenues
Gross as a Principal versus Net as an Agent.

Accrual
revenues also include certain other gains and losses that relate to these activities or for which accrual accounting is required.

We
include in accrual revenues the effects of hedge accounting for derivative contracts that qualify as hedges of our sales of products or services. Substantially all of the derivatives
that we designate as hedges are cash flow hedges. We recognize the effective portion of hedge gains or losses in revenues during the same period in which we record the revenues from the hedged
transaction. We record any hedge ineffectiveness in revenues when it occurs. We discuss our hedge accounting policy in theDerivatives and Hedging
Activitiessection later in this Note.

We
may make or receive cash payments at the time we assume previously existing power sale agreements for which the contract price differs from current market prices. We also may
designate a derivative as NPNS after its inception. We recognize the value of these derivatives in our Consolidated Balance sheets as an "Unamortized energy contract" asset or liability. We amortize
these assets and liabilities into revenues based on the present value of the underlying cash flows provided by the contracts.

The
following table summarizes the primary components of accrual revenues:

ActivityComponent of
Accrual Revenues

Nonregulated
Physical
Energy
Delivery

Regulated
Electricity
and Gas
Sales

Other
Nonregulated
Products and
ServicesGross amounts receivable for sales of products or services based on contract, tariff, or spot price

X

X

XReclassification of net gains/losses on cash flow hedges from AOCI

XIneffective portion of net gains/losses on cash flow hedges

XAmortization of acquired energy contract assets or liabilities

XRecovery or refund of deferred SOS and gas cost adjustment clause regulatory assets/liabilities



X


Mark-to-Market Accounting

We record revenues using the mark-to-market method of accounting for transactions under derivative contracts for which we are
not permitted, or do not elect, to use accrual accounting or hedge accounting. These mark-to-market transactions primarily relate to our risk management and trading activities,
our nonregulated retail gas customer supply activities, and economic hedges of other accrual activities. Mark-to-market revenues include:



Under
the mark-to-market method of accounting, we record any inception fair value of these contracts as derivative assets and liabilities at the time of contract
execution. We record subsequent changes in the fair value of these derivative assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income (Loss). We
discuss our mark-to-market accounting policy in theDerivatives and Hedging Activitiessection later in this Note.

94

---



Table of Contents

Equity in Earnings

We include equity in earnings from our investments in qualifying facilities and power projects, joint ventures, and Constellation Energy
Partners LLC (CEP) in "Nonregulated revenues" in our Consolidated Statements of Income (Loss) in the period they are earned.

Fuel and Purchased Energy Expenses

Sources of Fuel and Purchased Energy Expenses

We
incur fuel and purchased energy costs for:



We
report these costs in "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss). We also include certain fuel-related direct costs, such as
ancillary services purchased from independent system operators, transmission costs, brokerage fees, and freight costs in the same category in our Consolidated Statements of Income (Loss).

Fuel
and purchased energy costs from nonregulated activities result from contracts or other purchases that generally reflect market prices in effect at the time that we executed the
contract or the purchase occurred. BGE's costs of electricity and gas for resale under regulated activities reflect actual costs of purchases, adjusted to reflect provisions of orders of the Maryland
PSC and the FERC. In certain cases, these orders require BGE to defer the difference between certain portions of its actual costs and the amount presently billable to customers. BGE records these
differences as regulatory assets or liabilities, which we discuss in more detail inNote 6. We describe the effects of these orders on BGE's fuel
and purchased energy expense below.

Regulated Electric

BGE provides market-based standard offer electric service to residential and small commercial customers for the indefinite future and for large
commercial and industrial customers for varying periods beyond June 30, 2004, depending on customer load. BGE charges these customers SOS rates that are designed to recover BGE's wholesale
power supply costs and include an administrative fee consisting of a shareholder return component and an incremental cost component.

BGE
defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge portion of SOS rates in a
given period. BGE either bills or refunds its customers the difference in the future and includes amortization of the deferred amounts in fuel and purchased energy expense. Therefore, BGE's fuel and
purchased energy expense approximates the amount of the related commodity charge included in revenues for the period, reflecting actual costs adjusted for the effects of the regulatory deferral
mechanism.

Regulated Gas

BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses." These clauses include a market-based
rates incentive mechanism that requires BGE to compare its actual cost of gas to a market index (a measure of the market price of gas for that period) and share the difference equally between
shareholders and customers. This sharing mechanism excludes fixed-price contracts which the Maryland PSC requires BGE to procure for at least 10%, but not more than 20%, of forecasted system supply
requirements for the November through March period.

BGE
defers the difference between the portion of its actual gas commodity costs subject to the market-based rates incentive mechanism and what it collects from customers under the
commodity charge in a given period. BGE either bills or refunds its customers the portion of this difference to which they are entitled through an adjustment to the price of gas service in future
periods and includes amortization of the deferred amounts in fuel and purchased energy expense. Therefore, BGE's fuel and purchase energy expense approximates the amount of the related commodity
charge included in revenues for the period, reflecting actual gas costs adjusted for the effects of the regulatory deferral mechanism.

Selection
of Accounting Treatment

We
determine the appropriate accounting treatment for fuel and purchased energy costs based on the nature of the transaction, governing accounting standards and, where
required, by applying judgment as to the most transparent presentation of the economics of the underlying transactions. We utilize two primary accounting treatments to recognize and report these costs
in our Consolidated Statements of Income (Loss):



We
describe each of these accounting treatments below.

Accrual Accounting

Under accrual accounting, we record fuel and purchased energy expenses in the period when we consume the fuel or purchase the electricity or other
commodity for resale. We use accrual accounting to recognize substantially all of our fuel and purchased energy expenses as part of our physical delivery activities. We make these purchases using a
variety of instruments, including non-derivative transactions, derivatives that qualify for and are designated as NPNS, and spot-market purchases, including settlements with
independent system operators. These transactions also include power purchase agreements that qualify as operating leases, for which fuel and purchased energy consists of both fixed capacity payments
and variable payments based on the actual output of the plants. We discuss the NPNS election later in this Note underDerivatives and Hedging
Activities.

In
certain cases, we use mark-to-market accounting rather than accrual accounting for recognizing fuel and purchased energy expenses on physical commodity
derivatives if we have not designated those contracts as NPNS.

95

---



Table of Contents

We
include in accrual fuel and purchased energy expenses the effects of hedge accounting for derivative contracts that qualify as hedges of our fuel and purchased energy costs.
Substantially all of the derivatives that we designate as hedges are cash flow hedges. We recognize the effective portion of hedge gains or losses in fuel and purchased energy expenses during the same
period in which we record the costs from the hedged transaction. We record any hedge ineffectiveness in expense when it occurs. We discuss our use of hedge accounting in the Derivatives and Hedging Activitiessection later in this Note.

We
may make or receive cash payments at the time we assume previously existing power purchase agreements or other contracts for which the contract price differs from current market
prices. We recognize the cash payment at inception in our Consolidated Balance sheets as an "Unamortized energy contract" asset or liability. We amortize these assets and liabilities into fuel and
purchased energy expenses based on the present value of the underlying cash flows provided by the contracts.

The
following table summarizes the primary components of accrual purchased fuel and energy expense:

ActivityComponent of
Accrual Fuel and
Purchased Energy
Expense

Nonregulated
Physical
Energy
Delivery

Regulated
Electricity
and Gas
Sales

Other
Nonregulated
Products and
ServicesActual costs of fuel and purchased energy

X

X

XReclassification of net gains/losses on cash flow hedges from AOCI

XIneffective portion of net gains/losses on cash flow hedges

XAmortization of acquired energy contract assets or liabilities

XDeferral or amortization of deferred SOS and gas cost adjustment clause regulatory assets/liabilities



X


Mark-to-Market Accounting

We record fuel and purchased energy expenses using the mark-to-market method of accounting for transactions under derivative
contracts for which we are not permitted, or do not elect, to use accrual accounting or hedge accounting in order to match the earnings impacts of those activities to the greatest extent permissible.
These mark-to-market transactions primarily relate to our physical international coal purchase contracts. Mark-to-market costs include:



Under
the mark-to-market method of accounting, we record any inception fair value of these contracts as derivative assets and liabilities at the time of contract
execution. We record subsequent changes in the fair value of these derivative assets and liabilities on a net basis in "Fuel and purchased energy expense" in our Consolidated Statements of Income
(Loss). We discuss our mark-to-market accounting policy in theDerivatives and Hedging Activitiessection later in this Note.

Derivatives and Hedging Activities

We engage in electricity, natural gas, coal, emission allowances, and other commodity marketing and risk management activities as
part of our merchant energy business. In order to manage our exposure to commodity price fluctuations, we enter into energy and energy-related derivative contracts traded in the
over-the-counter markets or on exchanges. These contracts include:



We
use interest rate swaps to manage our interest rate exposures associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and
to optimize the mix of fixed and floating-rate debt. We use foreign currency swaps to manage our exposure to foreign currency exchange rate fluctuations.

Selection
of Accounting Treatment

We
account for derivative instruments and hedging activities in accordance with SFAS No. 133,Accounting for Derivative Instruments and
Hedging Activities, as amended and interpreted. SFAS No. 133 permits several possible accounting treatments for derivatives that meet all of the applicable requirements
of that standard. SFAS No. 133 requires mark-to-market as the default accounting treatment for all derivatives unless they qualify, and we specifically designate them,
for one of the other accounting treatments. Derivatives designated for any of the other elective accounting treatments must meet specific, restrictive criteria prescribed by SFAS No. 133, both
at the time of designation and on an ongoing basis.

SFAS
No. 133 provides for the following permissible accounting treatments for derivatives:



96

---



Table of Contents



Each
of the accounting treatments for derivatives affects our financial statements in substantially different ways as summarized below:

Recognition and MeasurementAccounting
TreatmentBalance Sheet

Income StatementMark-to-market

  Recorded at fair value

  Changes in fair value recognized in earningsCash flow hedge

  Recorded at fair value
  Effective changes in fair value recognized in accumulated other comprehensive income

  Ineffective changes in fair value recognized in earnings
  Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurringFair value hedge

  Recorded at fair value
  Changes in fair value of the hedged asset or liability recorded as adjustment to its book value

  Changes in fair value recognized in earnings
  Changes in fair value of hedged asset or liability recognized in earningsNPNS (accrual)

  Fair value not recorded
  Accounts receivable or accounts payable recorded when derivative settles

  Changes in fair value not recognized in earnings
  Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed


Mark-to-Market

We generally apply mark-to-market accounting for risk management and trading activities because changes in fair value more
closely reflect the economic performance of the activity. However, we also use mark-to-market accounting for derivatives related to the following physical energy delivery
activities:



We
may record origination gains associated with derivatives subject to mark-to-market accounting. Origination gains represent the initial fair value of certain
structured transactions that our portfolio management and trading operation executes to meet the risk management needs of our customers. Historically, transactions that result in origination gains
have been unique and resulted in individually significant gains from a single transaction. We generally recognize origination gains when we are able to obtain observable market data to validate that
the initial fair value of the contract differs from the contract price.

Cash Flow Hedge

We generally elect cash flow hedge accounting for most of the derivatives that we use to hedge market price risk for our physical energy delivery
(generation and customer supply) activities because accrual accounting more closely aligns the timing of earnings recognition, cash flows, and the underlying business activities. We only use fair
value hedge accounting on a limited basis.

We
use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all
derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a daily basis for all existing hedges. We calculate
the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of
expected cash flows from the hedge.

We
discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or
exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but
continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

NPNS

We elect NPNS accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities
expected to be used or sold over a reasonable period in the normal course of business. Once we elect NPNS classification for a given contract, we do not subsequently change the election and treat the
contract as a derivative using mark-to-market or hedge accounting. However, if we were to determine that a transaction designated as NPNS no longer qualified for the NPNS
election, we would have to record the fair value of that contract on the balance sheet at that time and immediately recognize that amount in earnings.

Fair
Value

We
record mark-to-market and hedge derivatives at fair value, which represents an exit price for the asset or liability from the perspective of a
market participant. An exit price is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. While some of our derivatives relate to commodities or
instruments for which quoted market prices are available from external sources, many other commodities and related contracts are not actively traded. Additionally, some contracts include quantities
and other factors that vary over time. As a result, often we must use modeling techniques to estimate expected future market prices, contract quantities, or both in order to determine fair value.

97

---



Table of Contents

The
prices, quantities, and other factors we use to determine fair value reflect management's best estimates of inputs a market participant would consider. We record valuation
adjustments to reflect uncertainties associated with estimates inherent in the determination of fair value that are not incorporated in market price information or other market-based estimates we use
to determine fair value. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and
determining the level of such adjustments and changes in those levels.

The
valuation adjustments we record include the following:



We
discuss derivatives and hedging activities as well as how we determine fair value in detail inNote 13.

Balance Sheet Netting

We often transact with counterparties under master agreements and other arrangements that provide us with a right of setoff of amounts due to us and
from us in the event of bankruptcy or default by the counterparty. We report these transactions on a net basis in our Consolidated Balance Sheets in accordance with FASB Interpretation No. 39, Offsetting Amounts Related
to Certain Contracts.During 2007, the FASB issued Staff Position FIN 39-1, Amendment of FASB Interpretation No. 39, which was effective January 1, 2008. We
discuss Staff Position FIN 39-1 in
more detail later inNote 1.

We
apply balance sheet netting separately for current and noncurrent derivatives. Current derivatives represent the portion of derivative contract cash flows expected to occur within
12 months, and noncurrent derivatives represent the portion of those cash flows expected to occur beyond 12 months. Within each of these categories, we net all amounts due to and from
each counterparty under master agreements into a single net asset or liability. We include fair value cash collateral amounts received and posted in determining this net asset and liability amount.

Unamortized Energy Assets and Liabilities

Unamortized energy contract assets and liabilities represent the remaining unamortized balance of non-derivative energy
contracts that we acquired, certain contracts which no longer qualify as derivatives due to the absence of a liquid market, or derivatives designated as NPNS that we had previously recorded as
"Derivative assets or liabilities." The initial amount recorded represents the fair value of the contract at the time of acquisition or designation, and the balance is amortized over the life of the
contract in relation to the present value of the underlying cash flows. The amortization of these values is discussed in theRevenuesand Fuel and Purchased Energy
Expensessections of this Note.

Credit Risk

Credit risk is the loss that may result from counterparty non-performance. We are exposed to credit risk, primarily
through our merchant energy business. We use credit policies to manage our credit risk, including utilizing an established credit approval process, daily monitoring of counterparty limits, employing
credit mitigation measures such as margin, collateral or prepayment arrangements, and using master netting agreements. We measure credit risk as the replacement cost for open energy commodity and
derivative positions (both mark-to-market and accrual) plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents
unrealized gains, less any unrealized losses where we have a legally enforceable right of setoff.

Electric
and gas utilities, municipalities, cooperatives, generation owners, and energy marketers comprise the majority of counterparties underlying our assets from our wholesale
marketing and risk management activities. We held cash collateral from these counterparties totaling $258.3 million as of December 31, 2008 and $269.9 million as of
December 31, 2007. These amounts are included in "Customer deposits and collateral" in our Consolidated Balance Sheets.

Taxes

We summarize our income taxes inNote 10. BGE and our other subsidiaries
record their allocated share of our consolidated federal income tax liability using the percentage complementary method specified in U.S. income tax regulations. As you read this section, it may be
helpful to refer toNote 10.

Income Tax Expense

We have two categories of income tax expensecurrent and deferred. We describe each of these below:



Tax Credits

We have deferred the investment tax credits associated with our regulated business and assets previously held by our regulated business in our
Consolidated Balance Sheets. The investment tax credits are amortized evenly to income over the life of each property. We reduce current income tax expense in our Consolidated Statements of Income
(Loss) for the investment tax

98

---



Table of Contents

credits
and other tax credits associated with our nonregulated businesses.

Through
December 31, 2007, we held certain investments in facilities that manufactured solid synthetic fuel produced from coal as defined under the Internal Revenue Code for which
we claimed tax credits on our Federal income tax return. Because the federal tax credit for synthetic fuel produced from coal expired on December 31, 2007, these facilities ceased fuel
production on that date. We recognized the tax benefit of these credits in our Consolidated Statements of Income (Loss) when we believe it is highly probable that the credits will be sustained.

Deferred Income Tax Assets and Liabilities

We must report some of our revenues and expenses differently for our financial statements than for income tax return purposes. The tax effects of the
temporary differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and liabilities using
income tax rates that are currently in effect. During 2007, the State of Maryland increased its corporate income tax rate from 7% to 8.25%.

A
portion of our total deferred income tax liability relates to our regulated business, but has not been reflected in the rates we charge our customers. We refer to this portion of the
liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further
inNote 6.

State and Local Taxes

State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income (Loss).

Taxes Other Than Income Taxes

BGE collects from certain customers franchise and other taxes that are levied by state or local governments on the sale or distribution of gas and
electricity. We include these types of taxes in "Taxes other than income taxes" in our Consolidated Statements of Income (Loss). Some of these taxes are imposed on the customer and others are imposed
on BGE. We account for the taxes imposed on the customer on a net basis, which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. We account for
the taxes imposed on BGE on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, we record the taxes accounted for on a gross basis as revenues in the
accompanying Consolidated Statements of Income (Loss) for BGE as follows:

Year Ended December 31,

2008

2007

2006(In millions)Taxes other than income taxes included in revenuesBGE

$
73.2

$
77.0

$
74.0


Unrecognized Tax Benefits

We adopted FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, on
January 1, 2007 (FIN 48). FIN 48 requires us to recognize in our financial statements the effects of uncertain tax positions if these positions meet a
"more-likely-than-not" threshold. For those uncertain tax positions that we have recognized in our financial statements, we establish liabilities to reflect the
portion of those positions we cannot conclude are "more-likely-than-not" to be realized upon ultimate settlement. These are referred to as liabilities for
unrecognized tax benefits under FIN 48. We recognize interest and penalties related to unrecognized tax benefits in "Income tax expense" in our Consolidated Statements of Income (Loss).

The
following table summarizes our total unrecognized tax benefits at January 1, 2007, the date of adoption of FIN 48:

At January 1, 2007Total liabilities reflected in our balance sheet for unrecognized tax benefits of $56.7 million less $12.1 million of interest and
penalties

$
44.6Other unrecognized tax benefits not reflected in our balance sheet


59.4Total unrecognized tax benefits

$
104.0


The adoption of FIN 48 did not have a material impact on BGE's financial results.

Other
unrecognized tax benefits relate to outstanding federal and state refund claims for which no tax benefit was previously provided in our financial statements because the claims do
not meet the "more-likely-than-not" threshold. Included in this amount is $52.0 million of refund claims that have been disallowed by the applicable tax
authorities for which we assess the probability of tax benefit recognition to be remote.

We
discuss our unrecognized tax benefits in more detail inNote 10.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average number of
common shares outstanding for the year. Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were
exercised or converted into common stock.

Our
dilutive common stock equivalent shares primarily consist of stock options and other stock-based compensation awards. The following table presents stock options that were not
dilutive and were excluded from the computation of diluted EPS

99

---



Table of Contents

in
each period, as well as the dilutive common stock equivalent shares as follows:

Year Ended December 31,

2008

2007

2006(In millions)Non-dilutive stock options


2.6





Dilutive common stock equivalent shares


5.5


2.3


2.0


As a result of the Company incurring a loss for the year ended December 31, 2008, diluted common stock equivalent shares were not included in
calculating diluted EPS.

We
issued to MidAmerican 19,897,322 shares of Constellation Energy's common stock upon the conversion of the Series A Preferred Stock, which happened upon the termination of the
merger agreement with MidAmerican on December 17, 2008. We discuss this feature of the Series A Preferred Stock in more detail in Note 9. These additional shares did not materially impact
our earnings per share for 2008, but they will impact our earnings per share in future
periods.

Stock-Based Compensation

Under our long-term incentive plans, we have granted stock options, performance-based units, service-based units,
performance and service-based restricted stock, and equity to officers, key employees, and members of the Board of Directors. We discuss these awards in more detail in Note 14.

SFAS
No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Equity-based
compensation awards include stock options, restricted stock, and any other share-based payments. Under SFAS No. 123R, we recognize compensation cost ratably or in tranches (depending if the
award has cliff or graded vesting) over the period during which an employee is required to provide service in exchange for the award, which is typically a one to five-year period. We use a
forfeiture assumption based on historical experience to estimate the number of awards that are expected to vest during the service period, and ultimately true-up the estimated expense to
the actual expense associated with vested awards. We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option-pricing model and we remeasure the fair value of
liability awards each reporting period. We do not capitalize any portion of our stock-based compensation.

Cash and Cash Equivalents

All highly liquid investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

As of December 31, 2008 and 2007, our restricted cash primarily represented the proceeds that we received on
December 17, 2008 from issuance of the Series B Preferred Stock to EDF Group and related entities (EDF). These proceeds are restricted for payment of the 14% Senior Note that was held by
MidAmerican. We used these proceeds to repay the Senior Note in January 2009. Our restricted cash also includes proceeds from financing for the acquisition, construction, installation and equipping of
certain sewage and solid waste disposal facilities at our Brandon Shores coal-fired generating plant in Maryland.

As
of December 31, 2008 and 2007, BGE's restricted cash primarily represented funds restricted for the repayment of the rate stabilization bonds. We discuss the rate stabilization
bonds in more detail inNote 9.

Accounts Receivable and Allowance for Uncollectibles

Accounts receivable, which includes cash collateral posted in our margin account with third-party brokers, are stated at the
historical carrying amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollectibles based on our expected exposure to the credit risk of customers
based on a variety of factors.

Materials, Supplies, and Fuel Stocks

We record our fuel stocks, emissions credits, renewable energy credits, coal held for resale, and materials and supplies at the lower
of cost or market. We determine cost using the average cost method for our entire inventory.

Financial Investments

InNote 4, we summarize the financial investments that are in our Consolidated
Balance Sheets.

SFAS
No. 115,Accounting for Certain Investments in Debt and Equity Securities,applies particular requirements to some of our
investments in debt and equity securities. We report those investments at fair value, and we use either specific identification or average cost to determine their cost for computing realized gains or
losses.

Available-for-Sale Securities

We classify our investments in the nuclear decommissioning trust funds as available-for-sale securities. We describe the
nuclear decommissioning trusts and the related asset retirement obligations later in this Note. In addition, we have investments in marketable equity securities and trust assets securing certain
executive benefits that are classified as available-for-sale securities.

We
include any unrealized gains on our available-for-sale securities in "Accumulated other comprehensive loss" in our Consolidated Statements of Common
Shareholders' Equity and Comprehensive Income.

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

Long-Lived Assets

We evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired
when certain conditions exist. SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets,provides the accounting
requirements for impairments of long-lived assets and proved gas properties. We test our long-lived assets and proved gas properties for recoverability whenever events or
changes in circumstances indicate that their carrying amount may not be recoverable.

100

---



Table of Contents

We
determine if long-lived assets and proved gas properties are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting
records. We record an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset. Cash flows for long-lived assets are determined at the
lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Proven gas properties' cash flows are determined at the field level.
Undiscounted expected future cash flows include risk-adjusted probable and possible reserves. We are also required to evaluate our equity-method and cost-method investments
(for example, in partnerships that own power projects) for impairment. Accounting Principles Board (APB) No. 18,The Equity Method of Accounting for Investments in
Common Stock(APB No. 18), provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB
No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

We
evaluate unproved gas producing properties at least annually to determine if they are impaired under SFAS No. 19,Financial Accounting and Reporting by
Oil and Gas Producing Properties. Impairment for unproved property occurs if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience
necessitates a valuation allowance.

We
use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs.
However, actual future market prices and project costs could vary from those used in our impairment evaluations, and the impact of such variations could be material.

Debt and Equity Securities

We evaluate our investments in debt and equity securities for impairment under FASB Staff Position (FSP) SFAS 115-1 and SFAS
No. 124-1 (FSP SFAS No. 115-1 and 124-1),The Meaning of Other-Than-Temporary Impairment and Its
Application to Certain Investments.FSP SFAS 115-1 and 124-1 require us to determine whether a decline in fair value of an investment below book
value is other than temporary. If we determine that the decline in fair value is other than temporary, we write-down the cost basis of the investment to fair value as a new cost basis.
Securities held in our nuclear decommissioning trust funds for which the market value is below book value must be written down to fair value because such declines in fair value are considered other
than temporary.

Goodwill and Intangible Assets

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and
other intangibles under the provisions of SFAS No. 142,Goodwill and Other Intangible Assets.We do not amortize goodwill. SFAS No. 142
requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of
the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived
assets as previously discussed. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of
goodwill is greater than its fair value. SFAS No. 142 also requires the amortization of intangible assets with finite lives. We discuss the changes in our goodwill and intangible assets in more
detail inNote 5.

Property, Plant and Equipment, Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations

We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 144.

Original
cost includes:



We
own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to
the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of
$285.1 million at December 31, 2008 and $208.6 million at December 31, 2007. Each owner is responsible for financing its proportionate share of the plants' working funds.
Working funds are used for operating expenses and capital expenditures. Operating expenses related to these plants are included in "Operating expenses" in our Consolidated Statements of Income (Loss).
Capital costs related to these plants are included in "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets.

The
"Nonregulated property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $1,230.8 million at
December 31, 2008 and $329.6 million at December 31, 2007.

When
we retire or dispose of property, plant and equipment, we remove the asset's cost from our Consolidated Balance Sheets. We charge this cost to accumulated depreciation for assets
that were depreciated under the group, straight-line method. This includes regulated property, plant and equipment and nonregulated generating assets. For all other assets, we remove the
accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income (Loss).

The
costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income (Loss) as incurred.

Our
oil and gas exploration and production activities consist of working interests in gas producing fields. We account for these activities under the successful efforts method of
accounting. Acquisition, development, and exploration costs are capitalized as permitted by SFAS No. 19. Costs of drilling exploratory wells are initially capitalized and later charged to

101

---



Table of Contents

expense
if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.

There
were no capitalized exploratory well costs at December 31, 2008 and $16.8 million at December 31, 2007, which do not include amounts that were capitalized and
subsequently expensed within the same period. There were no material well costs capitalized at December 31, 2007 and 2006 that were reclassified in 2008 and 2007, respectively, to wells,
facilities and equipment based on the determination of proved reserves.

There
were $9.7 million of capitalized exploratory well costs charged to expense in 2008, with no material charges in 2007 and 2006. Additionally, there were $13.3 million
of capitalized exploratory well costs sold during 2008 in conjunction with the sales of oil and natural gas properties in North Louisiana, South Texas, and Arkansas. There were no remaining
capitalized exploratory well costs pending the determination of proved reserves at December 31, 2008. However, there were $12.9 million of such costs at December 31, 2007.

Depreciation and Depletion Expense

We compute depreciation for our generating, electric transmission and distribution, and gas distribution facilities. We compute depletion for our
exploitation and production activities. Depreciation and depletion are determined using the following methods:



Other
assets are depreciated primarily using the straight-line method and the following estimated useful lives:

Asset

Estimated Useful LivesBuilding and improvements

5 - 50 yearsOffice equipment and furniture

3 - 20 yearsTransportation equipment

5 - 15 yearsComputer software

3 - 10 years


Amortization Expense

Amortization is an accounting process of reducing an asset amount in our Consolidated Balance Sheets over a period of time that approximates the
useful life of the related item. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income (Loss). We discuss the types of
assets that we amortize and the periods over which we amortize them in more detail inNote 5.

Accretion Expense

SFAS No. 143,Accounting for Asset Retirement Obligations,provides the accounting
requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. FIN 47,Accounting
for Conditional Asset Retirement Obligationsan Interpretation of FASB Statement No. 143,clarifies that asset retirement obligations that are conditional
upon a future event are subject to the provisions of SFAS No. 143. Our conditional asset retirement obligations relate primarily to asbestos removal at certain of our generating facilities.

At
December 31, 2008, $964.4 million of our total asset retirement obligation of $987.3 million was associated with the decommissioning of our nuclear power
plantsCalvert Cliffs Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear Station (Nine Mile Point) and R. E. Ginna Nuclear Power Plant (Ginna). The remainder of our asset
retirement obligations is associated with our other generating facilities and certain other long-lived assets.

From
time to time, we will perform studies to update our asset retirement obligations. We record a liability when we are able to reasonably estimate the fair value of any future legal
obligations associated with retirement that have been incurred and capitalize a corresponding amount as part of the book value of the related long-lived assets.

The
increase in the capitalized cost is included in determining depreciation expense over the estimated useful lives of these assets. Since the fair value of the asset retirement
obligations is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period to "Accretion of asset retirement obligations" in our
Consolidated Statements of Income (Loss) until the settlement of the liability. We record a gain or loss when the liability is settled after retirement for any difference between the accrued liability
and actual costs. The change in our "Asset retirement obligations" liability during 2008 was as follows:

(In millions)Liability at January 1, 2008

$
917.6Liabilities incurred


1.7Liabilities settled


(0.7
)Accretion expense


68.4Revisions to cash flows


2.9Other


(2.6
)Liability at December 31, 2008

$
987.3


Nuclear Decommissioning

We are obligated to decommission our Calvert Cliffs, Nine Mile Point, and Ginna nuclear power plants after these plants cease operation in accordance
with Nuclear Regulatory Commission (NRC) regulations and relevant state requirements.

102

---



Table of Contents

In
March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of
Maryland officials which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement, BGE customers will be relieved of the potential future liability for
decommissioning Constellation Energy's Calvert Cliffs Unit 1 and Unit 2, scheduled to occur no earlier than 2034 and 2036, respectively. BGE will continue to collect the $18.7 million annual
nuclear decommissioning charge from all electric customers through 2016 and continue to rebate this amount to residential electric customers, as previously required by Senate Bill 1, which had been
enacted in June 2006. We discuss the Maryland settlement agreement in more detail inNote 2.

The
following is a summary of our asset retirement obligations associated with the decommissioning of these plants:

At December 31,

2008

2007(in millions)Calvert Cliffs

$
333.4

$
309.5Nine Mile Point


368.4


341.9Ginna


262.6


245.9Total

$
964.4

$
897.3


In accordance with NRC regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to decommission our nuclear plants. Our
nuclear decommissioning trust funds and the investment earnings thereon are restricted to meeting the costs of decommissioning the plants in accordance with NRC regulations and relevant state
requirements. We develop our decommissioning trust fund strategy based on estimates of the costs to perform the decommissioning and the timing of incurring those costs. When developing our estimates
of future fund earnings, we consider our asset allocation investment strategy, rates of return earned historically, and current market conditions. Investments by nuclear decommissioning trust funds
are guided by the "prudent man" investment principle. The funds are prohibited from investing directly in Constellation Energy or its affiliates and any other entity owning a nuclear power plant.

The
assets in the trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets. We classify the investments in the nuclear decommissioning trust funds
as available-for-sale securities, and we report these investments at fair value in our Consolidated Balance Sheets as previously discussed in this Note.

The
external trust fund balances were as follows:

At December 31,

2008

2007(in millions)Calvert Cliffs

$
346.9

$
457.4Nine Mile Point


460.3


610.2Ginna


199.1


263.2Total

$
1,006.3

$
1,330.8


The $324.5 million decrease in the value of the external trust fund balances is comprised of impairment charges of $165.0 million, recorded in
"Other (Expense) Income," unrealized losses of $207.0 million, recorded in "Accumulated other comprehensive loss," partially offset by contributions of $18.7 million and income of
$28.8 million.

Our
contributions to the nuclear decommissioning trust funds for Calvert Cliffs were $18.7 million for 2008, $8.8 million for 2007, and $8.8 million for 2006. No
contributions were made to the trust funds for Nine Mile Point and Ginna during the years ended December 31, 2008, 2007, and 2006.

Nuclear Fuel

We amortize the cost of nuclear fuel, including the quarterly fees we pay to the Department of Energy (DOE) for the future disposal
of spent nuclear fuel, based on the energy produced over the life of the fuel. These fees are based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in
"Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss).

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest

Our nonregulated businesses capitalize interest costs under SFAS No. 34,Capitalizing Interest
Costs,for costs incurred to finance our power plant construction projects, real estate developed for internal use, and other capital projects.

Allowance for Funds Used During Construction (AFC)

BGE finances its construction projects with borrowed funds and equity funds. BGE is allowed by the Maryland PSC and the FERC to record the costs of
these funds as part of the cost of construction projects in its Consolidated Balance Sheets. BGE does this through the AFC, which it calculates using rates authorized by the Maryland PSC and the FERC.
BGE bills its customers for the AFC plus a return after the utility property is placed in service.

The
AFC rates are 9.4% for electric distribution plant, 8.8% for electric transmission plant, 8.5% for gas plant, and 9.1% for common plant. BGE compounds AFC annually.

Long-Term Debt and Credit Facilities

We defer all costs related to the issuance of long-term debt and credit facilities. These costs include underwriters'
commissions, discounts or premiums, other costs such as external legal,

103

---



Table of Contents

accounting,
and regulatory fees, and printing costs. We amortize these costs into interest expense over the life of the debt or credit facility.

When
BGE incurs gains or losses on debt that it retires prior to maturity, it amortizes those gains or losses over the remaining original life of the debt in accordance with regulatory
requirements.

Accounting Standards Issued

SFAS No. 141 Revised

In December 2007, the FASB issued SFAS No. 141 Revised (SFAS No. 141R),Business
Combinations. SFAS No. 141R revises SFAS 141,Business Combinations.SFAS No. 141R requires the purchaser
of a business to determine the fair value of the consideration exchanged as of the acquisition date (i.e., the date the acquirer obtains control). Previously, an acquisition was valued as of
the date the parties agree upon the terms of the transaction. SFAS No. 141R also modifies, among other things, the accounting for direct costs associated with an acquisition, contingencies
acquired, and contingent consideration. We will apply SFAS No. 141R for all future business combinations that close after January 1, 2009.

SFAS No. 160

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements, an
amendment of ARB No. 51. SFAS No. 160 provides that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be
reported as equity in the consolidated financial statements. SFAS No. 160 requires that companies:



SFAS
No. 160 must be applied prospectively as of January 1, 2009, except that existing noncontrolling interests must be reclassified retrospectively for all periods
presented.

The
adoption of SFAS No. 160 will affect how we present and disclose noncontrolling interests in our financial statements and how we account for future changes in ownership
interests in subsidiaries. Specifically, we will:



Upon
closing of our Investment Agreement with EDF, under SFAS No. 160, we anticipate that we will deconsolidate our subsidiary that owns our nuclear generation and operation
business, record our ownership interest in this entity at fair value, and recognize a material gain on both the portion of the subsidiary sold to EDF and our retained interest.

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161,Disclosures About Derivative Instruments and Hedging
Activities. SFAS No. 161 is effective beginning January 1, 2009 and requires entities to provide expanded disclosure about derivative instruments and hedging
activities regarding: (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or
could have) on an entity's financial position, financial performance, and cash flows. SFAS No. 161 requires expanded disclosures, but does not change the accounting for derivatives. We do not
expect the adoption of this standard to have a material impact on our, or BGE's, financial results because it only provides for additional disclosure.

FSP SFAS No. 132R-1

In December 2008, the FASB issued Staff Position (FSP) No. 132R-1,Employers' Disclosures
about Postretirement Benefit Plan Assets, which amends SFAS No. 132R,Employers' Disclosures about Pensions and Other Postretirement
Benefits.The FSP expands the disclosures set forth in SFAS No. 132R by adding required disclosures about: (1) how investment allocation decisions are made by
management, (2) major categories of plan assets, and (3) significant concentrations of risk. In addition, the FSP requires disclosure of information about the valuation of plan assets
similar to that required under SFAS No. 157,Fair Value Measurements. Those disclosures include: (1) the level within the fair value
hierarchy in which the fair value measurements of plan assets fall, (2) information about the inputs and valuation techniques used to measure the fair value of plan assets, and (3) a
reconciliation of the beginning and ending balances of plan assets valued using significant unobservable inputs. The disclosures about plan assets required by the FSP must be provided for years ending
after December 15, 2009. We are currently evaluating the impact of this FSP, but, because it only provides for additional disclosure, we do not expect the adoption of this standard to have a
material impact on our, or BGE's, financial results.

Accounting Standards Adopted

FSP FIN 39-1

In April 2007, the FASB issued FSP FIN 39-1,Amendment of FASB Interpretation
No. 39. As amended, FIN 39,Offsetting of Amounts Related to Certain Contracts, requires an entity to report all
derivatives recorded at fair value net of any associated fair value cash collateral with the same counterparty under a master netting arrangement. Therefore, effective January 1, 2008, we
reported all derivatives recorded at fair value net of the associated fair value cash collateral. We applied the provisions of FSP FIN 39-1 by adjusting all financial statement
periods

104

---



Table of Contents

presented,
which reduced total assets at December 31, 2007 by $203.4 million. We present the fair value cash collateral that has been offset against our net derivative positions as part
of our adoption of SFAS No. 157 inNote 13.

SFAS No. 157

Effective January 1, 2008, we adopted SFAS No. 157,Fair Value Measurements, which
defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements.

SFAS
No. 157 does not require any new fair value measurements but instead applies when other accounting pronouncements require or permit fair value measurements. SFAS
No. 157 defines fair value as the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit
price). Unless otherwise noted, when we use the term "fair value" throughout the footnotes related to 2008 we are referring to fair value as defined by SFAS No. 157.

We
applied the provisions of SFAS No. 157 prospectively as of January 1, 2008. We will apply the provisions of SFAS No. 157 for nonfinancial assets and liabilities
effective January 1, 2009. Prior to the adoption of SFAS No. 157, we determined fair value for derivative liabilities for which prices are not available from external sources by
discounting the expected cash flows from the contracts using a risk-free discount rate. We did not reflect our own credit risk in determining fair value for these liabilities. SFAS
No. 157 requires us to record all liabilities measured at fair value by including the effect of our own credit risk. Accordingly, we applied a credit-spread adjustment in order to reflect our
own credit risk in determining fair value for these liabilities, which reduced the recorded amount of these liabilities as of the date of adoption. As a result, during the first quarter of 2008 we
recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in
earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial.

We
discuss SFAS No. 157 in more detail including the required disclosures inNote 13.

FSP SFAS No. 157-3

In October 2008, the FASB issued FSP SFAS No. 157-3,Determining the Fair Value of a Financial Asset When
the Market for That Asset is Not Active. This FSP does not change the guidance contained in SFAS No. 157; rather, it clarifies the application of SFAS No. 157 in
a market that is not active. This FSP was effective for the period ended September 30, 2008, and the adoption of this FSP did not have an effect on our financial results.

FSP SFAS No. 140-4 and FIN 46R-8

In December 2008, the FASB issued FSP SFAS No. 140-4 and FIN 46(R)-8,Disclosures About
Transfers of Financial Assets and Interests in Variable Interest Entities,which requires public entities to make additional disclosures about transfers of financial assets and
involvement with variable interest entities. This FSP does not change the accounting for transfers of financial assets or variable interest entities; rather, it only requires additional disclosures
related to such items. We reflected the provisions of the FSP inNote 4.

105

---



2Other Events

2008 Events

Pre-Tax

After-Tax(In millions)Merger termination and strategic alternatives costs

$
(1,204.4
)
$
(1,204.4
)Impairment losses and other costs


(741.8
)

(470.7
)Workforce reduction costs


(22.2
)

(13.4
)Emissions allowances write-down


(46.7
)

(28.7
)Net gain on sales of upstream gas assets


25.5


16.0Gain on sale of dry bulk vessel


29.0


18.9Maryland settlement credit (after-tax amount reflects the effective tax rate impact on BGE)


(189.1
)

(110.5
)Impairment of nuclear decommissioning trust assets


(165.0
)

(82.0
)Total other items

$
(2,314.7
)
$
(1,874.8
)


Merger Termination and Strategic Alternatives Costs

We incurred costs during 2008 related to the terminated merger agreement with MidAmerican, the conversion of Series A Preferred Stock, the
execution of the Investment Agreement and related agreements with EDF, and our pursuit
of other strategic alternatives. These costs totaled $1,204.4 million pre-tax. We did not record a tax benefit for any of these costs in our Consolidated Statement of Income (Loss)
in 2008.

A
significant portion of these costs was incurred pursuant to the termination of the merger agreement with MidAmerican and the conversion of the Series A Preferred Stock.
Specifically, Constellation Energy incurred the following charges:



The
above amounts do not include $150 million of cash received from EDF in conjunction with the Investment Agreement entered into on December 17, 2008. We will record this
$150 million as additional purchase price for EDF's purchase of a 49.99% membership interest in our nuclear generation and operation business. This amount has been deferred on our Consolidated
Balance Sheets pending closing of the sale.

BGE
recorded $16 million as its allocable portion of these costs through November 30, 2008 when the merger with MidAmerican was still pending. However, in light of the EDF
transaction involving an investment in our nonregulated nuclear generation and operation business rather than a merger with Constellation Energy, BGE has not been allocated any further costs effective
in December 2008 and all of the previously allocated costs recorded by BGE have been allocated to the merchant energy segment.

Impairment Losses and Other Costs

Impairment Evaluations

We discuss our evaluation of assets for impairment and other than temporary declines in value in Note 1. We perform impairment evaluations for our long-lived assets, equity method
investments, and goodwill when triggering events
occur that would indicate that the potential for an impairment exists. We perform an impairment evaluation for our nuclear decommissioning trust fund assets quarterly.

In
addition, Statement of Financial Accounting Standards (SFAS) No. 142,Goodwill and Other Intangible Assetsrequires that
goodwill be evaluated for impairment on an annual basis regardless of whether any triggering events have occurred. Our accounting policy is to perform an annual goodwill impairment review in the third
quarter of each year.

During
the third quarter of 2008, the following triggering events resulted in the need for us to perform impairment analyses:



As
a result of these evaluations, we recorded impairments of our upstream gas properties, goodwill, and certain investments in debt and equity securities. Additionally, in the fourth
quarter of 2008, there were continued declines in commodity prices and the overall stock market. This led to further impairment of our upstream gas properties, and certain investments in debt and
equity securities. We describe the impairment evaluations we performed in the following sections.

Long-Lived
Assets

We
evaluate potential impairment of long-lived assets classified as held for use under SFAS No. 144,Accounting for the Impairment
or Disposal of Long-Lived Assets, which provides that an impairment loss shall be recognized if the carrying amount of

106

---



such
assets is not recoverable. The carrying amount of an asset held for use is not recoverable if it exceeds the total undiscounted future cash flows expected to result from the use and eventual
disposition of the asset.

This
evaluation requires us to estimate uncertain future cash flows. In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and
other factors that may affect future cash flows. The assumptions we use are consistent with forecasts that we make for other purposes (for example, in preparing our other earnings forecasts) or have
been adjusted to reflect relevant subsequent changes. If we are considering alternative courses of action (such as the potential sale of an asset), we probability-weight the alternative courses of
action to estimate the expected cash flows.

We
use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future
market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Upstream Gas Properties

During 2008, we performed impairment analyses for our upstream gas properties as a result of the following triggering events:



We
evaluate proved properties under SFAS No. 144. We evaluate unproved property under SFAS No. 19,Financial Accounting and Reporting by Oil and Gas
Producing Properties. Unproved property is impaired if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a
valuation allowance. To the extent that unproved property is part of an asset that contains proved property, the accounting guidance under SFAS No. 144 applies for evaluating impairment.

We
have begun the process necessary to sell our upstream gas properties, and, while we sold some of these properties in the fourth quarter of 2008, we have not yet obtained the formal
approval of our Board of Directors for the sale of our other remaining properties. This approval is required to commit to a plan for sale. As a result, we continue to classify these properties as held
for use as of December 31, 2008. Accordingly, our impairment evaluation consisted of estimating expected undiscounted cash flows under various scenarios as discussed below and comparing those
amounts to the carrying value.

We
evaluated our upstream gas portfolio for impairment at the individual property level, which is the lowest level of identifiable cash flows, since each property has separate financial
statements identifying and capturing the related cash flows. We evaluated a combination of cash flows from operations scenarios for the remaining period for which we expect to hold these properties as
well as estimates of proceeds from each property's ultimate disposal. The primary inputs to our estimates of cash flows from operations were reserve estimates and natural gas and oil prices based upon
forward curves and modeled data for unobservable periods. The primary inputs to our estimate of proceeds from disposal were a combination of external market bids, internal models and reserve reports,
and information from external advisors assisting in the sale of these assets. We maximized the use of market information to the extent it was available. We evaluated several possible courses of action
and timing, and we probability-weighted the cash flows associated with each of these scenarios based upon our best estimates of the expected outcome and timing in order to arrive at each property's
expected future cash flows.

Our
evaluation indicated that estimated cash flows were less than the carrying value of three of our seven upstream gas properties at September 30, 2008. At December 31,
2008, our evaluation indicated that estimated cash flows were less than the carrying value for two additional properties and for one property in which that property's estimated cash flows were less
than its post-impairment carrying value at September 30, 2008 as well. The primary factors leading to the declines in expected cash flows were the decrease in market prices for
natural gas and oil during the third and fourth quarters of 2008 combined with our expectation that we would sell these properties rather than hold them for their full useful lives.

As
a result, we recorded the following pre-tax impairment charges:

Asset Groups

At
September 30,
2008

At
December 31,
2008(In millions)Interest in proved and unproved natural gas and crude oil reserves in south Texas

$
62.6

$
Interest in proved natural gas reserves in the Rocky Mountains


73.2


Interest in proved and unproved natural gas reserves in the Offshore-Gulf of Mexico


7.1


3.8Interest in proved and unproved crude oil and natural gas reserves in eastern Oklahoma





30.0Interest in proved and unproved natural gas reserves in central Oklahoma





153.2Total impairment charges

$
142.9

$
187.0


We recorded these impairment charges in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and they are reported in our
merchant energy business results.

Generating Plants

We evaluated the impact of the events that occurred in 2008 on the recoverability of our generating plants. Based upon our consideration of these
events and the status of the generating plant's activities, we determined that our generating plants are

107

---



not
impaired as of September 30, 2008 and December 31, 2008.

Debt
and Equity Securities and Investments

We
evaluated certain of our investments in debt and equity securities (both equity-method and cost-method investments) in light of recent declines in market
prices during the third and fourth quarters of 2008. The investments we evaluated include our investment in CEP, other marketable securities, our nuclear decommissioning trust fund assets, and our
investment in UniStar Nuclear Energy (UNE). We record an impairment if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than
temporary." We do not record an impairment if the decline in value is temporary and we have the ability and intent to hold the investment until its value recovers.

In
making this determination, we evaluate the reasons for an investment's decline in value, the extent and length of that decline, and factors that indicate whether and when the value
will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these securities is considered other than
temporary and we write them down to fair value.

The
fair value of our investment in CEP fell below carrying value at the end of August, and continued to decline through the end of 2008. As of September 30, 2008, the fair value
of our investment in CEP based upon its closing unit price was $73 million, which was lower than its carrying value of $128 million. As of December 31, 2008, the fair value of our
investment in CEP based upon its closing unit price was $17 million, which was lower than its carrying value at December 31, 2008 of $87 million.

While
CEP's estimate of net asset value exceeded our carrying value, the decline in fair value of our investment in CEP reflects a number of other factors, including:



As
a result of evaluating these factors at both September 30, 2008 and December 31, 2008, we determined that the declines in the value of our investment at both dates were
other than temporary. Therefore, we recorded a $54.7 million pre-tax impairment charge at September 30, 2008 and an additional $69.7 million pre-tax
impairment charge at December 31, 2008 to write-down our investment to fair value. We recorded these charges in "Impairment losses and other costs" in our Consolidated Statements of
Income (Loss). To the extent that the market price of our investment declines further in future quarters, we may record additional write-downs if we determine that those additional declines are other
than temporary.

As
a result of significant declines in the stock market during 2008, the fair values of certain of our marketable securities and many of the securities held in our nuclear
decommissioning trust fund declined below book value. As a result, we recorded impairment charges of $31.0 million and $122.0 million pre-tax at September 30, 2008 and
December 31, 2008, respectively, for our nuclear decommissioning trust fund investments in the "Other (expense) income" line in our Consolidated Statements of Income (Loss). We had previously
recorded impairment charges for our nuclear decommissioning trust fund at both March 31, 2008 and June 30, 2008, totaling $12.0 million pre-tax. We also recorded an
impairment charge of $7.0 million pre-tax for certain of our other marketable securities in the fourth quarter of 2008. In addition, we recorded other changes in the fair value of
our nuclear decommissioning trust fund assets that are not impaired in other comprehensive income. We discuss the assets within our nuclear decommissioning trust funds in more detail in Note 4.

We
also evaluated the impact of the events that occurred in 2008 on the recoverability of our investment in UNE. Based upon our consideration of these events and the status of UNE's
activities, we determined that our investment in UNE is not impaired as of December 31, 2008.

The
estimates we utilize in evaluating impairment of our debt and equity securities require judgment and the evaluation of economic and other factors that are subject to variation, and
the impact of such variations could be material.

Goodwill

Goodwill
is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the
provisions of SFAS No. 142, which requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired.
Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, in the third quarter of each year, we evaluate goodwill for impairment.

The
primary judgment affecting our impairment evaluation is the requirement to estimate fair value of the reporting units to which the goodwill relates. We evaluate impairment at the
reportable segment level, which is the lowest level in the organization that constitutes a business for which discreet financial information is available.

Prior
to September 30, 2008, substantially all of our goodwill related to our merchant energy segment. The lack of observable market prices for the merchant energy segment
required us to estimate fair value, which we determined on a preliminary basis using the income valuation approach by computing discounted cash flows, consistent with prior evaluations. Although our
estimate of discounted cash flows exceeded the carrying value of the merchant energy segment, because our common stock continued to trade at a price less than carrying value for the entire company
throughout the last half of September and all of October, we also estimated fair value for the merchant energy segment using current market price information.

108

---



The
primary inputs and assumptions to our estimate of fair value based upon market information were as follows:



Using
this information, we deducted the estimated fair value of non-merchant energy segment businesses from the fair value of Constellation Energy as a whole in order to
estimate the fair value of the merchant energy segment as of September 2008. Based upon this estimate, the fair value of the merchant energy segment was substantially less than its carrying value. The
primary difference between this estimate and our modeled estimates using the discounted cash flow income approach is that the market price approach incorporated the market's valuation discount
associated with our merchant energy segment due to its significant liquidity and collateral requirements. We believe that this was a more appropriate method for estimating fair value than the modeled
valuation techniques because it incorporated observable market information to a greater extent, which reflects current market conditions, and because it required fewer and less subjective judgments
and estimates than our modeled estimates.

As
a final consideration during our September 2008 impairment evaluation, we also evaluated the circumstances surrounding MidAmerican's purchase of Constellation Energy and whether the
current market price of our common stock should be considered to represent fair value for accounting purposes. While the transaction price for the purchase of Constellation Energy resulted from
negotiations that occurred over an abbreviated period of time during which the Company was experiencing financial difficulty, ongoing trading of the stock at levels approximating the transaction price
represented the market's present assessment of fair value in a liquid, active market. This is consistent with guidance issued by the Securities Exchange Commission Office of the Chief Accountant and
FASB Staff on the determination of fair value in distressed markets.

Based
on our evaluation of these alternative measures of fair value, we determined that the fair value of the merchant energy business segment was less than its carrying value.
Therefore, in order to measure the potential impairment of goodwill, we estimated the fair value of the merchant energy segment's assets and liabilities. We determined that the fair value of its
assets net of liabilities substantially exceeded the segment's total fair value, indicating that the merchant energy segment's goodwill was impaired as of September 30, 2008. Accordingly, we
recorded a pre-tax charge of $266.5 million to write-off the entire balance of our merchant energy segment goodwill substantially all of which was recorded in the third
quarter of 2008. This charge is recorded in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss).

Other Costs

In September 2008, we entered into a non-binding agreement to settle a class action complaint that alleged a subsidiary's ash placement
operations at a third party site damaged surrounding properties. In December 2008, the settlement was approved by the court. As a result of this agreement, we recorded a $14.0 million
pre-tax charge net of an expected insurance recovery.

Workforce Reduction Costs

We incurred costs related to workforce reduction efforts initiated at our nuclear generating facilities in 2006 and 2007. We substantially completed
both of these workforce reduction efforts during 2008.

In
September 2008, our merchant energy business approved a restructuring of the workforce at our Customer Supply operations. We recognized a $2.5 million pre-tax
charge during 2008 related to the elimination of approximately 100 positions associated with this restructuring. The restructuring is expected to be completed within the next 12 months.

During
the fourth quarter of 2008, we approved a restructuring of the workforce across all of our operations. We recognized a $19.7 million pre-tax charge in 2008
related to the elimination of approximately 380 positions. The restructuring is expected to be completed within the next twelve months. We expect to incur additional workforce reduction costs in 2009.

Emissions Allowances

The Clean Air Interstate Rule (CAIR) required states in the eastern United States to reduce emissions of sulfur dioxide (SO2) and
established a cap-and-trade program for annual nitrogen oxide (NOx) emission allowances. On July 11, 2008, the United States Court of Appeals for the D.C.
Circuit (the "Court") issued an opinion vacating CAIR, subject to petitions for rehearing. The Environmental Protection Agency (EPA) filed a petition for rehearing. On December 23, 2008, the
Court reversed its earlier decision to revoke CAIR and will allow CAIR to remain in effect until it is replaced by a revised rule issued by the EPA that would preserve the environmental rules
established by CAIR. The Court did not propose a deadline by which the EPA must correct the flaws identified with CAIR but it did state that it will accept petitions if the EPA does not remedy the
problems previously identified in its July 11, 2008 opinion.

As
a result of the Court's December 2008 decision, the annual NOx program will become effective in 2009 as originally established by CAIR. In addition, since the December
2008 decision, market prices for 2009 NOx allowances have increased significantly, with lesser increases shown in allowances for subsequent years. There was also an increase in trading
volumes for annual NOx. For the SO2 program, the EPA will be required to issue a new rule that would replace the allowances issued under Title IV of the Clean Air Act with a
new, reduced pool of allowances which would meet or exceed existing CAIR targets. Market prices for SO2 allowances have also risen since the Court's decision.

We
account for our emission allowance inventory at the lower of cost or market, which includes consideration of our expected requirements related to the future generation of electricity.
The weighted-average cost of our 2008 SO2 allowance inventory in excess of amounts needed to satisfy these requirements was greater than market value at June 30, 2008

109

---



and
market prices decreased further for both SO2 and annual NOx emission allowances through September 30, 2008. After giving consideration to the Court's July 11,
2008 decision and the subsequent decline in the market price of these allowances, we recorded a write-down of our SO2 allowance inventory totaling $22.1 million
pre-tax to reflect the June 30, 2008 market prices. At September 30, 2008, we recorded an additional write-down of our SO2 emission allowance
inventory and recorded a write-down of our annual NOx allowance inventory totaling $58.9 million to reflect the September 30, 2008 prices. These write-downs were
recorded in the "Nonregulated revenues" line in our Consolidated Statements of Income (Loss). The third quarter 2008 write-down was partially offset by
mark-to-market gains totaling $22.2 million pre-tax on derivative contracts for the forward sale of emission allowances. This gain reflects the impact of
lower market prices on the value of those derivative contracts.

Due
to the recent increases in SO2 and NOx emission allowance prices stemming from the December 23, 2008 Court ruling, we evaluated the value of our
emissions allowances and determined that, in accordance with Accounting Principles Board Opinion No. 28,Interim Financial Information, a partial
reversal of prior interim period write-downs was appropriate. At December 31, 2008, we reversed $11.4 million of the second and third quarter of 2008 write-downs. The prices at
December 31, 2008 create a new cost basis for SO2 and annual NOx emission allowances and cannot be further written-up in future periods. Our
mark-to-market gains on derivative contracts for the forward sale of emission allowances were $0.7 million for the quarter ended December 31, 2008. At this time,
we cannot predict the outcome of any further judicial, regulatory or legislative developments or their impact on the emission allowance markets.

Net Gain on Sale of Upstream Gas Assets

On March 31, 2008, we sold our working interest in oil and natural gas producing properties in Oklahoma to CEP, a related party, and
recognized a gain of $14.3 million, net of the minority interest gain of $0.7 million. We discuss this transaction in more detail in Note 16.

In
addition, on June 30, 2008, our merchant energy business sold a portion of its working interests in proved natural gas reserves and unproved properties in Arkansas to an
unrelated party for total proceeds of $145.4 million, which is subject to certain purchase price adjustments. Our merchant energy business recognized a $77.7 million pre-tax
gain on this sale.

In
December 2008, our merchant energy business sold working interests in proved natural gas reserves in Wyoming, and our equity investment in certain entities that own interests in
proved natural gas reserves and unproved properties in Texas and Montana to unrelated parties for total proceeds of $55.7 million, subject to certain purchase price adjustments. Our merchant
energy business recognized a $67.2 million pre-tax loss on these sales.

The
net gain is included in "Net Gains on Sales of Upstream Gas Assets" line in our Consolidated Statements of Income (Loss).

Gain on Sale of Dry Bulk Vessel

On July 10, 2008, a shipping joint venture, in which our merchant energy business has a 50% ownership interest, sold one of the six dry bulk
vessels it owns. Our merchant energy business recognized a $29.0 million pre-tax gain on this sale. The gain is included in "Nonregulated revenues" line in our Consolidated
Statements of Income (Loss).

Maryland Settlement AgreementCustomer Rate Credit

In March 2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the
Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory and legislative issues. On April 24, 2008, the Governor of
Maryland signed enabling legislation, which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement:



110

---





2007 Events

Pre-Tax

After-Tax(In millions)Impairment losses and other costs

$
(20.2
)
$
(12.2
)Workforce reduction costs


(2.3
)

(1.4
)Gain on sales of equity of CEP


63.3


39.2Loss from discontinued operationsHigh Desert


(2.4
)

(0.3
)Puna





(0.6
)Total loss from discontinuedoperations


(2.4
)

(0.9
)Total other items

$
38.4

$
24.7


Impairment Losses and Other Costs

In connection with the termination of the merger agreement with FPL Group, Inc. (FPL Group) in October 2006, we acquired certain rights
relating to a wind development project in Western Maryland. In the second quarter of 2007, we elected not to make the additional investment that was required at that time to retain our rights in the
project; therefore, we recorded a charge of $20.2 million pre-tax to write-off our investment in these development rights.

Workforce Reduction Costs

In June 2007, we approved a restructuring of the workforce at our Nine Mile Point nuclear facility related to the elimination of 23 positions. We
recognized costs of $2.3 million pre-tax related to recording a liability for severance and other benefits under our existing benefit programs.

The
following table summarizes the status of this involuntary severance liability for Nine Mile Point at December 31, 2008:

(In millions)Initial severance liability balance (1)

$
2.6Amounts recorded as pension and postretirement liabilities


(1.5
)Net cash severance liability


1.1Cash severance payments


(0.7
)Other


(0.4
)Severance liability balance at December 31, 2008

$



Gain on Sales of Equity of CEP

In November 2006, CEP, a limited liability company formed by Constellation Energy completed an initial public offering of 5.2 million common
units at $21 per unit. See details under2006 Eventslater in this Note. In April 2007, CEP acquired 100% ownership of certain coalbed methane
properties located in the Cherokee Basin in Kansas and Oklahoma. This acquisition was funded through CEP's sale of equity in which we did not participate.

As
a result of the April 2007 equity issuance by CEP, our ownership percentage in CEP fell below 50 percent. Therefore, during the second quarter of 2007, we deconsolidated CEP
and began accounting for our investment using the equity method under Accounting Principles Board Opinion (APB) No. 18,The Equity Method of Accounting for Investments
in Common Stock.We discuss the equity method of accounting in more detail inNote 1.

In
July and September 2007, CEP issued additional equity. In connection with our equity ownership in CEP, we recognize gains on CEP's equity issuances in the period that the equity is
sold as common units or when converted to common units. The details of the 2007 CEP equity issuances, as well as the gains recognized by us, are summarized below:

Units
Issued

Price/
Unit

Proceeds
to CEP

Pre-tax
gain(In millions, except price/unit)April 2007 SaleCommon units


2.2

$
26.12

$
58

$
12.5Class E units


0.1


25.84


2


0.4July 2007 SaleCommon units


2.7


35.25


94


20.0Class F units


2.6


35.25


92


11.2September 2007 SaleCommon units


2.5


42.50


105


19.2


Discontinued operations

In the fourth quarter of 2006, we completed the sale of six natural gas-fired plants, including the High Desert facility, which was
classified as discontinued operations. We recognized an

111

---



after-tax
loss of $0.3 million as a component of "Income (loss) from discontinued operations" for 2007 due to post-closing working capital and income tax adjustments. In
addition, during 2007, we recognized an after-tax loss of $0.6 million relating to income tax adjustments arising from the June 2004 sale of a geothermal generating facility in
Hawaii that was also previously classified as discontinued operations.

Presented
in the table below are the amounts related to discontinued operations that are included in "Income from discontinued operations" in our Consolidated Statements of Income
(Loss):

High Desert

International Investments

Total2007

2006

2007

2006

2007

2006(In millions)Revenues

$


$
161.2

$


$


$


$
161.2(Loss) income before income taxes


(2.4
)

108.9








(2.4
)

108.9Net (loss) income


(0.3
)

70.2








(0.3
)

70.2Pre-tax gain on sale





185.2





1.4





186.6After-tax gain on sale





116.7





0.9





117.6(Loss) income from discontinued operations, net of taxes


(0.3
)

186.9





0.9


(0.3
)

187.8


During 2007, we recognized an after-tax loss from discontinued operations of $(0.6) million, related to tax adjustments from the sale of
Puna, a Hawaiian Geothermal facility, in 2004.

2006 Events

Pre-Tax

After-Tax(In millions)Gain on sale of gas-fired plants

$
73.8

$
47.1Workforce reduction costs


(28.2
)

(17.0
)Merger-related costs


(18.3
)

(5.7
)Gain on initial public offering of CEP


28.7


17.9Income from discontinued operationsHigh Desert


294.1


186.9International investments


1.4


0.9Total income from discontinued operations


295.5


187.8Total other items

$
351.5

$
230.1


Sale of Gas-Fired Plants

In December 2006, we completed the sale of the following natural gas-fired plants owned by our merchant energy business:

Facility

Capacity
(MW)

Unit Type

LocationHigh Desert


830

Combined Cycle

CaliforniaRio Nogales


800

Combined Cycle

TexasHolland


665

Combined Cycle

IllinoisUniversity Park


300

Peaking

IllinoisBig Sandy


300

Peaking

West VirginiaWolf Hills


250

Peaking

Virginia


We sold these gas-fired plants for cash of $1.6 billion, and recognized a pre-tax gain on the sale of $259.0 million of
which $73.8 million was included in "Gain on sale of gas-fired plants" and $185.2 million was included in "Income from discontinued operations" in our Consolidated Statements
of Income.

At
the time of the agreement for sale, we evaluated these plants for classification as discontinued operations under SFAS No. 144. Discontinued operations classification only
applies to assets held for sale that meet the definition of a component of an entity. A component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and
for financial reporting purposes, from the rest of the entity.

High
Desert met the requirements to be classified as a discontinued operation because it had a power sales agreement for its full output, was determined to be a component of
Constellation Energy, and had separately identifiable cash flows. The table above provides additional detail about the amounts recorded in "Income from discontinued operations" related to our High
Desert facility.

The
remaining gas-fired plants were managed within our merchant energy business as a group or on a portfolio basis because they have aggregated risks, were hedged as a group,
and generated joint cash flows. These gas-fired plants do not meet the requirements to be classified as discontinued operations. The results of operations for these gas-fired
plants, as well as the $73.8 million pre-tax gain on sale, remain classified in continuing operations.

International Investments

In the fourth quarter of 2005, we completed the sale of Constellation Power International Investments, Ltd. (CPII). We recognized an
after-tax gain of $0.9 million for the year ended December 31, 2006 due to the resolution of an outstanding contingency related to the sale. We discuss the details of the
outstanding contingency later in this Note.

Workforce Reduction Costs

In March 2006, we approved a restructuring of the workforce at our Ginna nuclear facility. In connection with this restructuring, 32 employees were
terminated. During the quarter ended

112

---



March 31,
2006, we recognized costs of $2.2 million pre-tax related to recording a liability for severance and other benefits under our existing benefit programs.

We
completed this workforce reduction effort in 2006. As a result, no involuntary severance liability was recorded at December 31, 2006.

In
July 2006, we announced a planned restructuring of the workforce at our Nine Mile Point nuclear facility. We recognized costs during the quarter ended September 30, 2006 of
$15.1 million pre-tax related to the elimination of 126 positions associated with this restructuring. We also initiated a restructuring of the workforce at our Calvert Cliffs
nuclear facility during the third quarter of 2006 and we recognized costs of $2.9 million pre-tax related to the elimination of 30 positions associated with this restructuring.

In
addition, we incurred a pre-tax settlement charge of $12.7 million in accordance with Statement of Financial Accounting Standards (SFAS) No. 88, Employers' Accounting for Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination Benefits. This charge reflects recognition
of the portion of deferred actuarial gains and losses associated with employees who were terminated as part of the restructuring or retired in 2006 and who elected to receive their pension benefit in
the form of a lump-sum payment. In accordance with SFAS No. 88, a settlement charge must be recognized when lump-sum payments exceed annual pension plan service and
interest cost. The total SFAS No. 88 settlement charge incurred in 2006 includes a pre-tax charge of $8.0 million as a result of the Nine Mile Point restructuring. We discuss
the settlement charges that we recorded during 2006 inNote 7.

The
following table summarizes the status of this involuntary severance liability for Nine Mile Point and Calvert Cliffs at December 31, 2008:

(In millions)Initial severance liability balance

$
19.6Amounts recorded as pension and postretirement liabilities


(7.3
)Net cash severance liability


12.3Cash severance payments


(12.3
)Other


Severance liability balance at December 31, 2008

$



The severance liability above includes $1.6 million of costs that the joint owner of Nine Mile Point Unit 2 reimbursed
us.

Merger-Related costs

We incurred costs during 2006 related to the proposed merger with FPL Group. The merger was terminated in October 2006. These costs totaled
$18.3 million pre-tax for 2006. In addition, during 2006 we recognized tax benefits of $5.3 million on merger costs incurred in 2005 that were not considered deductible for
income tax purposes until the termination of the merger in 2006. Our total pre-tax merger-related costs were $35.3 million.

Initial Public Offering of CEP

In November 2006, CEP, a limited liability company formed by Constellation Energy, completed an initial public offering of 5.2 million common
units at $21 per unit. The initial public offering resulted in cash proceeds of $101.3 million, after expenses associated with the offering, for Constellation Energy.

As
a result of the initial public offering of CEP, we recognized a pre-tax gain of $28.7 million, or $17.9 million after recording deferred taxes on the gain.

113

---



3Information by Operating Segment

Our reportable operating segments areMerchant Energy, Regulated Electric, and Regulated Gas:



Our
remaining nonregulated businesses:



In
connection with efforts to improve our liquidity and reduce our business risk:



We
believe that the successful execution of these initiatives, as well as our other initiatives being undertaken to reduce risk in our merchant energy business, will reduce our exposure
to activities that require contingent capital support and improve our liquidity. In turn, the results for our merchant energy business segment will be materially different from prior periods. We
discuss these strategies and their effect on liquidity inNote 8.

During
2006, we sold six of our gas-fired facilities. We discuss the sales of our gas-fired plants in more detail in Note 2.

Our
Merchant Energy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services that require different
technologies and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. We present a summary of information
by operating segment on the next page.

Divestitures

In 2009, we have made progress on many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our
business risk.

In
January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. In February 2009, we entered into a definitive agreement to sell
our Houston-based gas trading operation. Simultaneously, we signed a letter of intent to enter into a related transaction with an affiliate of the buyer under which that company would provide us with
the gas supply needed to support our retail gas customer supply business, while reducing our credit requirements. We expect that both of these sales will close by the end of the second quarter of
2009, subject to certain regulatory approvals and other standard closing conditions. Upon closing of these transactions, we expect to recognize an aggregate pre-tax loss of not more than
$200 million based on current commodity prices. The actual amount of the loss will be affected by the final consideration exchanged, which is based on the timing of the close, and by changes in
commodity prices. The impact on cash is not expected to be material.

Collectively,
we expect that both divestitures to return approximately $1 billion of currently posted collateral. In addition, we expect these divestitures to further reduce our
downgrade collateral requirements by approximately $400 million. These reductions are based on current commodity prices, the final terms of the transactions, and the timing of collateral to be
returned up to the close of the transactions, and, as a result, are subject to change.

114

---



Reportable SegmentsHolding
Company and
Other
Nonregulated
BusinessesMerchant
Energy
Business

Regulated
Electric
Business

Regulated
Gas
Business

Eliminations

Consolidated(In millions)2008Unaffiliated revenues

$
15,880.9

$
2,679.5

$
1,004.7

$
253.2

$


$
19,818.3Intersegment revenues


891.9


0.2


19.3


0.2


(911.6
)

Total revenues


16,772.8


2,679.7


1,024.0


253.4


(911.6
)

19,818.3Depreciation, depletion, and amortization


287.1


184.2


43.7


68.2





583.2Fixed charges


191.4


123.5


29.5


1.7


16.2


362.3Income tax expense (benefit)


(99.5
)

(4.9
)

25.5


0.6





(78.3
)Net (loss) income (1)


(1,357.4
)

1.1


37.2


4.7





(1,314.4
)Segment assets (2)


13,857.9


4,620.3


1,392.4


3,508.5


(1,095.0
)

22,284.1Capital expenditures


1,675.0


388.0


74.0


86.0





2,223.02007Unaffiliated revenues

$
17,545.1

$
2,455.6

$
943.0

$
249.5

$


$
21,193.2Intersegment revenues


1,199.4


0.1


19.8


0.3


(1,219.6
)

Total revenues


18,744.5


2,455.7


962.8


249.8


(1,219.6
)

21,193.2Depreciation, depletion, and amortization


269.9


187.4


46.8


53.7





557.8Fixed charges


86.9


107.6


30.9


8.6


71.6


305.6Income tax expense


332.7


64.6


22.8


8.2





428.3Income from discontinued operations


(0.9
)













(0.9
)Net income (3)


678.3


97.9


28.8


16.5





821.5Segment assets


15,947.7


4,378.4


1,293.6


458.6


(336.0
)

21,742.3Capital expenditures


1,178.0


340.0


62.0


85.0





1,665.02006Unaffiliated revenues

$
16,048.2

$
2,115.9

$
890.0

$
230.8

$


$
19,284.9Intersegment revenues


1,118.0





9.5


0.2


(1,127.7
)

Total revenues


17,166.2


2,115.9


899.5


231.0


(1,127.7
)

19,284.9Depreciation, depletion, and amortization


258.7


181.5


46.0


37.7





523.9Fixed charges


191.7


86.9


28.9


10.5


10.7


328.7Income tax expense (benefit)


250.2


78.0


27.0


(4.2
)




351.0Income from discontinued operations


186.9








0.9





187.8Net income (4)


767.0


120.2


37.0


12.2





936.4Segment assets


16,387.3


3,783.2


1,252.8


887.8


(509.5
)

21,801.6Capital expenditures


768.0


297.0


63.0


21.0





1,149.0


115

---



4Investments

Investments in Qualifying Facilities and Power Projects, CEP, and Joint Ventures

Investments in qualifying facilities, domestic power projects, joint ventures and CEP consist of the following:

At December 31,

2008

2007(In millions)Qualifying facilities and domestic power projects:Coal

$
119.5

$
119.6Hydroelectric


55.6


54.7Geothermal


37.0


37.6Biomass


58.2


43.6Fuel Processing


15.0


26.8Solar


6.9


7.0CEP


17.7


143.0Joint Ventures:Shipping JV


59.9


56.6UNE


51.0


52.2Other


0.2


1.1Total

$
421.0

$
542.2


Investments in qualifying facilities, domestic power projects, CEP and joint ventures were accounted for under the following methods:

At December 31,

2008

2007(In millions)Equity method

$
414.1

$
535.2Cost method


6.9


7.0Total

$
421.0

$
542.2


Our percentage voting interests in these investments accounted for under the equity method range from 20% to 50%. Equity in earnings of these investments was
$76.8 million in 2008, $8.3 million in 2007, and $13.8 million in 2006. The increase in equity earnings from 2007 to 2008 primarily relates to the $29.0 million
pre-tax gain recognized in 2008 by our shipping joint venture upon the sale of one dry bulk vessel and the cessation of operations at a synthetic fuel facility at December 31, 2007.

We
describe each of these investments below.

Qualifying Facilities and Power Projects

Our merchant energy business holds up to a 50% voting interest in 18 operating domestic energy projects that consist of electric generation, fuel
processing, or fuel handling facilities. Of these 18 projects, 16 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policies Act of 1978 based
on the facilities' energy source or the use of a cogeneration process.

CEP

In November 2006, CEP, a limited liability company formed by our merchant energy business, completed an initial public offering. As of
December 31, 2006, we owned approximately 54% of CEP and consolidated CEP. During the second quarter of 2007, CEP issued additional equity to the public and our ownership percentage fell below
50%. Therefore, we deconsolidated CEP and began accounting for our investment using the equity method under Accounting Principles Board Opinion (APB) No. 18,The Equity
Method of Accounting for Investments in Common Stock. As of December 31, 2008, we hold a 28.5% voting interest in CEP.

During
2008, as a result of significant declines in the stock market, we determined that the decline in the value of our investment in CEP is other than temporary. Therefore, we recorded
an approximately $124 million pre-tax impairment charge during 2008 to write-down our investment to fair value as of December 31, 2008.

Joint Ventures

In December 2006, we formed a shipping joint venture in which our merchant energy business has a 50% ownership interest. The joint venture currently
owns and operates five dry bulk vessels. The joint venture sold one dry bulk vessel in 2008. SeeNote 2for more detail on this sale. In 2008 and
2007, we made cash contributions of approximately $5 million and $57 million, respectively, to the joint venture.

In
August 2007, we formed a joint venture, UniStar Nuclear Energy, LLC (UNE) with EDF. We have a 50% ownership interest in this joint venture to develop, own, and operate new
nuclear projects in the United States and Canada. The agreement with EDF includes a phased-in investment of $625 million by EDF in UNE. In 2008, EDF invested $175 million in
UNE and we contributed land with a book value of $1.7 million. In 2007, EDF invested $350 million in UNE, and we contributed the new nuclear line of businesses we had developed over the
prior two years, which included assets with a book value of $48.7 million and the right to develop possible new nuclear projects at our existing nuclear plant locations. Upon reaching certain
licensing milestones, EDF will contribute up to an additional $100 million in UNE.

As
of December 31, 2008, UNE's capitalized construction work in progress was approximately $301 million. Such amounts are being capitalized based on UNE's assessment that
construction of new nuclear projects is probable. Should that expectation change, previously capitalized costs would be written off. In the event that our portion of any losses incurred by UNE exceed
our investment, we will continue to record those losses in earnings unless it is determined that UNE will cease operations and subsequently be dissolved.

116

---



Investments Classified as Available-for-Sale

We classify the following investments as available-for-sale:



This
means we do not expect to hold these investments to maturity, and we do not consider them trading securities. We record these investments at fair value on our Consolidated Balance
Sheets.

We
show the fair values, gross unrealized gains and losses, and adjusted cost basis for all of our available-for-sale securities in the following tables. We use
specific identification to determine cost in computing realized gains and losses.

At December 31, 2008

Adjusted
Cost

Unrealized
Gains

Unrealized
Losses

Fair
Value(In millions)Money market funds

$
17.6

$


$


$
17.6Marketable equity securities


700.9


41.5


(2.1
)

740.3Corporate debt and U.S. treasuries


224.8


6.8





231.6State municipal bonds


46.2


1.3





47.5Totals

$
989.5

$
49.6

$
(2.1
)
$
1,037.0




At December 31, 2007

Adjusted
Cost

Unrealized
Gains

Unrealized
Losses

Fair
Value(In millions)Money market funds

$
11.7

$


$


$
11.7Marketable equity securities


819.9


266.3


(0.2
)

1,086.0Corporate debt and U.S. treasuries


224.5


5.4





229.9State municipal bonds


48.3


2.5





50.8Totals

$
1,104.4

$
274.2

$
(0.2
)
$
1,378.4


In addition, the nuclear decommissioning trust funds included cash of $3.6 million at December 31, 2008. There was no cash at
December 31, 2007.

The
unrealized gains in the preceding tables consist primarily of $49.6 million and $256.7 million in 2008 and 2007, respectively, associated with the nuclear
decommissioning trust funds.

The
investments in our nuclear decommissioning trust funds are managed by third parties who have independent discretion over the purchases and sales of securities. We recognize
impairments for any of these investments for which the fair value declines below our book value. We recognized $165.0 million and $8.5 million in pre-tax impairment losses on
our nuclear decommissioning trust investments during 2008 and 2007, respectively. These impairments are included as part of gross realized losses in the following table.

Gross
and net realized gains and losses on available-for-sale securities were as follows:

Year ended December 31,

2008

2007

2006(In millions)Gross realized gains

$
49.6

$
33.5

$
13.3Gross realized losses


(210.4
)

(30.9
)

(13.0
)Net realized (losses) gains

$
(160.8
)
$
2.6

$
0.3


The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:

At December 31, 2008(In millions)Less than 1 year

$
15.21-5 years


75.25-10 years


89.5More than 10 years


99.2Total maturities of debt securities

$
279.1


Investments in Variable Interest Entities

We evaluate all transactions and relationships with potential variable interest entities (VIEs) in accordance with FASB
Interpretation No. 46R,Consolidation of Variable Interest EntitiesAn Interpretation of ARB No. 51(FIN 46R).

Our
overall methodology for evaluating transactions and relationships under FIN 46R includes the following:



In
performing the first step, the significant factors and judgments that we consider include:



For
each VIE identified, we evaluate whether we are the primary beneficiary of the VIE by considering:



117

---





Based
on our evaluation of the above factors and judgments, as of December 31, 2008, we consolidated two VIEs in which we are the primary beneficiary. Also, as of
December 31, 2008, we had significant interests in seven VIEs for which we did not have controlling financial interests and, accordingly, were not the primary beneficiary.

Consolidated Variable Interest Entities

In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy-remote limited liability company, to acquire and hold rate
stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess,
collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously
incurred power purchase costs that BGE deferred pursuant to Senate Bill 1.

BGE
determined that BondCo is a variable interest entity for which it is the primary beneficiary. As a result, BGE and we consolidated BondCo. We discuss the consolidation method of
accounting in more detail inNote 1.

The
carrying amounts and classification of BondCo's assets and liabilities included in our consolidated financial statements at December 31, 2008 are as follows:

(In millions)Current assets

$
23.7Noncurrent assets


Total Assets

$
23.7Current liabilities

$
61.5Noncurrent liabilities


510.9Total Liabilities

$
572.4


The BondCo assets above are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from
customers for rate stabilization charges to BondCo. During 2008, BGE remitted $87.2 million to BondCo.

BGE
did not provide any additional financial support to BondCo during 2008. Further, BGE does not have any contractual commitments or obligations to provide additional financial support
to BondCo unless additional rate stabilization bonds are issued. Alternatively, the BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges
are not sufficient to cover the bond principal and interest payments of BondCo.

During
2008, we consolidated a retail power supply VIE for which we became the primary beneficiary as a result of a modification to its contractual arrangements that changed the
allocation of the economic risks and rewards of the VIE among the variable interest holders. The consolidation of this VIE did not have a material impact on our financial results or financial
condition.

Unconsolidated Variable Interest Entities

As of December 31, 2008, we had significant interests in seven VIEs for which we are not the primary beneficiary. We have not provided any
material financial or other support to these entities during 2008, except for $5 million provided to two fuel supply entities for working capital needs.

The
nature of these entities and our involvement with them are described in the following table:

VIE Category

Nature of Entity Financing

Nature of Constellation Energy Involvement

Obligations or Requirement to Provide Financial Support

Date of
InvolvementPower contract monetization entities
(2 entities)

Combination of debt and equity financing

Power sale agreements, loans, and guarantees

$45.2 million in letters of credit

March 2005Power projects and fuel supply entities
(4 entities)

Combination of debt and equity financing

Equity investments and guarantees

$2.0 million debt guarantee and working capital funding

Prior to 2003Retail gas supply
(1 entity)

Equity financing and proceeds from gas sales

Gas supply agreement

$6.7 million in obligations under gas supply agreement and $3.7 million in payment guarantees

February 2008


For purposes of aggregating the various VIEs for disclosure, we evaluated the risk and reward characteristics for, and the significance of, each
VIE. We discuss in greater detail the nature of our involvement with the power contract monetization VIEs in thePower Contract Monetization VIEssection below.

The
following is summary information available as of December 31, 2008 about the VIEs in which we have a significant interest, but are not the primary beneficiary:

Power
Contract
Monetization
VIEs

All
Other
VIEs

Total(In millions)Total assets

$
669.8

$
303.0

$
972.8Total liabilities


526.5


99.1


625.6Our ownership interest





52.5


52.5Other ownership interests


143.3


151.4


294.7Our maximum exposure to loss


45.2


64.9


110.1Carrying amount and location of variable interest on balance sheet:Other investments





52.5


52.5


118

---



Our maximum exposure to loss is the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we
were required to fund the full amount of all guarantees associated with these entities. Our maximum exposure to loss as of December 31, 2008 consists of the following:



We
assess the risk of a loss equal to our maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In
addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of our variable interests in these variable interest entities.

Power Contract Monetization VIEs

In March 2005, our merchant energy business closed a transaction in which we assumed from a counterparty two power sales contracts with previously
existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts,
we sell power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity of the VIEs and we
loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity
interests to us in lieu of repaying the loan. In this event, we would have the right to seek recovery of our losses from the electric distribution utility.

119

---



5Intangible Assets

Goodwill

Goodwill is the excess of the cost of an acquisition over the fair value of the net assets acquired. As of December 31, 2008,
our goodwill balance was primarily related to our other nonregulated businesses. Prior to September 30, 2008, our goodwill balance was primarily related to our merchant energy business
acquisitions. Goodwill is not amortized; rather, it is evaluated for impairment at least annually. We evaluated our goodwill in 2008 and in 2007 and recorded a $266.5 million impairment charge
in 2008, which related solely to our merchant energy segment. We discuss this impairment charge in more detail inNote 2.

The
changes in the carrying amount of goodwill for the years ended December 31, 2008 and 2007 are as follows:

2008

Balance at
January 1,

Goodwill
Acquired

Other (1)

Balance at
December 31,(In millions)Goodwill

$
261.3

$
9.8

$
(266.5
)
$
4.6




2007

Balance at
January 1,

Goodwill
Acquired

Other (2)

Balance at
December 31,(In millions)Goodwill

$
157.6

$
103.4

$
0.3

$
261.3


For tax purposes, none of our goodwill balance at December 31, 2008 is deductible.

Intangible Assets Subject to Amortization

Intangible assets with finite lives are subject to amortization over their estimated useful lives. The primary assets included in
this category are as follows:

2008At December 31,





2007Gross
Carrying
Amount

Accumul-
ated
Amortiz-
ation

Net
Asset

Gross
Carrying
Amount

Accumul-
ated
Amortiz-
ation

Net
Asset(In millions)Software

$
554.9

$
(291.5
)
$
263.4

$
494.0

$
(232.3
)
$
261.7Permits and licenses


64.9


(10.0
)

54.9


62.3


(8.0
)

54.3Operating manuals and procedures


38.6


(8.6
)

30.0


38.6


(8.4
)

30.2Other


43.9


(22.6
)

21.3


26.8


(19.9
)

6.9Total

$
702.3

$
(332.7
)
$
369.6

$
621.7

$
(268.6
)
$
353.1


BGE had intangible assets with a gross carrying amount of $217.0 million and accumulated amortization of
$131.4 million at December 31, 2008 and $194.4 million and accumulated amortization of $124.5 million at December 31, 2007 that are included in the table above.
Substantially all of BGE's intangible assets relate to software.

We recognized amortization expense related to our intangible assets as follows:

Year Ended December 31,

2008

2007

2006(In millions)Nonregulated businesses

$
66.8

$
51.9

$
37.2BGE


20.1


20.2


18.6Total Constellation Energy

$
86.9

$
72.1

$
55.8


The following is our, and BGE's, estimated amortization expense related to our intangible assets for 2009 through 2013 for the intangible assets
included in our, and BGE's, Consolidated Balance Sheets at December 31, 2008:

Year Ended December 31,

2009

2010

2011

2012

2013(In millions)Estimated amortization expenseNonregulated businesses

$
62.2

$
48.7

$
38.4

$
23.6

$
15.1Estimated amortization expenseBGE


20.4


18.8


16.0


10.4


8.8Total estimated amortization expenseConstellation Energy

$
82.6

$
67.5

$
54.4

$
34.0

$
23.9


Unamortized Energy Contracts

As discussed inNote 1, unamortized energy contract assets and liabilities
represent the remaining unamortized balance of nonderivative energy contracts acquired, certain contracts which no longer qualify as derivatives due to the absence of a liquid market, or derivatives
designated as normal purchases and normal sales, which we previously recorded as derivative assets and liabilities.

During
2007, we acquired several pre-existing power-related contracts that had been originated by other parties in prior periods when market prices were lower than current
levels. The net proceeds received in this transaction were primarily recorded as a net liability in "Unamortized energy contracts."

We
present separately in our Consolidated Balance Sheets the net unamortized energy contract assets and liabilities for these contracts. The table below presents the gross and net
carrying amount and accumulated amortization of the net liability that we have recorded in our Consolidated Balance Sheets:

2008At December 31





2007Carrying
Amount

Accumul-
ated
Amortiz-
ation

Net
Liability

Carrying
Amount

Accumul-
ated
Amortiz-
ation

Net
Liability(In millions)Unamortized energy contracts, net

$
(2,332.3
)
$
1,286.8

$
(1,045.5
)
$
(2,290.0
)
$
889.5

$
(1,400.5
)


The table below presents the estimated net favorable impact on our operating results for the amortization for these assets and liabilities over
the next five-years:

Year Ended December 31,

2009

2010

2011

2012

2013(In millions)Estimated amortization

$
347.4

$
324.3

$
107.8

$
86.2

$
82.7


120

---



6Regulatory Assets (net)

As discussed inNote 1, the Maryland PSC and the FERC provide the final determination of the rates we
charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles
generally accepted in the United States of America. However, sometimes the Maryland PSC or FERC orders an accounting treatment different from that used by nonregulated companies to determine the rates
we charge our customers. When this happens, we must defer certain regulated expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our
Consolidated Statements of Income (Loss) (using amortization) when we include them in the rates we charge our customers.

We
summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.

At December 31,

2008

2007(In millions)Deferred fuel costsRate stabilization deferral

$
536.3

$
593.4Other


24.4


19.4Electric generation-related regulatory asset


118.0


135.9Net cost of removal


(198.0
)

(182.3
)Income taxes recoverable through future rates (net)


63.2


63.9Deferred smart energy savers program costs


15.6


Deferred postretirement and postemployment benefit costs


12.9


16.1Deferred environmental costs


7.7


8.9Workforce reduction costs





2.4Other (net)


(5.7
)

(6.6
)Total regulatory assets (net)


574.4


651.1Less: Current portion of regulatory assets (net)


79.7


74.9Long-term portion of regulatory assets (net)

$
494.7

$
576.2


Deferred Fuel Costs

Rate Stabilization Deferral

In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential
electric customers at 15% from July 1, 2006 to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to
purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In
addition, as required by Senate Bill 1, the Maryland PSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007
to January 1, 2008. During 2007, BGE deferred $306.4 million of electricity purchased for resale expenses and certain applicable carrying charges as a regulatory asset related to the
rate stabilization plans. During 2008 and 2007, BGE recovered $57.1 million and $39.2 million, respectively, of electricity purchased for resale expenses and carrying charges related to
the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when
collection from customers began in June 2007. Customers who participated in the deferral from June 1, 2007 to December 31, 2007 are repaying the deferred charges without interest over a
21-month period which began in April 2008 and ends in December 2009.

Other

As described inNote 1, deferred fuel costs are the difference between our actual costs of
purchased energy and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from our customers.

We
exclude deferred fuel costs from rate base because their existence is relatively short-lived. These costs are recovered in the following year through our fuel rates.

Electric Generation-Related Regulatory Asset

As a result of the deregulation of electric generation, BGE ceased to meet the requirements for the application of SFAS No. 71
for the previous electric generation portion of its business. In accordance with SFAS No. 101,Regulated EnterprisesAccounting for the Discontinuation of
Application of FASB Statement No. 71, and EITF 97-4,Deregulation of the Pricing of ElectricityIssues Related to
the Application of FASB Statements No. 71 and 101,BGE wrote-off all of its individual, generation- related regulatory assets and liabilities. BGE
established a single, generation-related regulatory asset to be collected through its regulated transmission and distribution business, which is being amortized on a basis that approximates the
pre-existing individual regulatory asset amortization schedules.

A
portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $72.4 million as of
December 31, 2008 and $81.1 million as of December 31, 2007. We will continue to amortize this amount through 2017.

Another
portion of this regulatory asset represented the decommissioning and decontamination fund payment for federal uranium enrichment facilities that did not earn a regulated rate of
return on the rate base investment. Prior to the deregulation of electric generation, these costs were recovered through the electric fuel rate mechanism, and were excluded from rate base. This amount
was $2.3 million at December 31, 2007. This amount was fully amortized at September 30, 2008.

121

---



Net Cost of Removal

As discussed inNote 1, we use the group depreciation method for the regulated
business. This method is currently an acceptable method of accounting under accounting principles generally accepted in the United States of America and has been widely used in the energy,
transportation, and telecommunication industries.

Historically,
under the group depreciation method, the anticipated costs of removing assets upon retirement were provided for over the life of those assets as a component of depreciation
expense. However, effective January 1, 2003, we adopted SFAS No. 143,Accounting for Asset Retirement Obligations.In addition to
providing the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets, SFAS No. 143
precludes the recognition of expected net future costs of removal as a component of depreciation expense or accumulated depreciation.

BGE
is required by the Maryland PSC to use the group depreciation method, including cost of removal, under regulatory accounting. For ratemaking purposes, net cost of removal is a
component of depreciation expense and the related accumulated depreciation balance is included as a net reduction to BGE's rate base investment. For financial reporting purposes, BGE continues to
accrue for the future cost of removal for its regulated gas and electric assets by increasing a regulatory liability. This liability is relieved when actual removal costs are incurred.

Income Taxes Recoverable Through Future Rates (net)

As described inNote 1, income taxes recoverable through future rates are the
portion of our net deferred income tax liability that is applicable to our regulated business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax
effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax
credits. We amortize these amounts as the temporary differences reverse.

Deferred Smart Energy Savers Program Costs

Deferred Smart Energy Savers Program costs are the costs incurred to implement demand response and advanced metering programs. These
programs are designed to help BGE manage peak demand, improve system reliability and improve service to customers by giving customers greater control over their energy use. Actual costs incurred in
the demand response program, which began in January 2008, are being amortized over a 5-year period from the date incurred pursuant to an order by the Maryland PSC.

Deferred Postretirement and Postemployment Benefit Costs

Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions,and
SFAS No. 112,Employers' Accounting for
Postemployment Benefits,in excess of the costs we included in the rates we charged our customers through 1997. We began amortizing these costs over a 15-year
period in 1998.

Deferred Environmental Costs

Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this
further inNote 12. We amortized $21.6 million of these costs (the amount we had incurred through October 1995) and are amortizing
$6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders. We applied for and
received rate relief for an additional $5.4 million of clean-up costs incurred during the period from July 2000 through November 2005. These costs are being amortized over a
10-year period that began in January 2006.

Workforce Reduction Costs

The portions of the costs associated with our Voluntary Special Early Retirement Program and workforce reduction programs that relate
to BGE's gas business were deferred as regulatory assets in accordance with the Maryland
PSC's orders in prior rate cases. As a result of a 2005 gas base rate case, the remaining regulatory assets associated with workforce reductions totaling $7.3 million as of December 31,
2005 were amortized over a 3-year period that began in January 2006. These remaining regulatory assets were previously amortized over 5-year periods beginning in January and
February 2002. This amount was fully amortized at December 31, 2008.

Other (Net)

Other regulatory assets are comprised of a variety of current assets and liabilities that do not earn a regulatory rate of return due
to their short-term nature.

122

---



7Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits

We offer pension, postretirement, other postemployment, and employee savings plan benefits. BGE employees participate in the benefit plans that we offer. We
describe each of our plans separately below. Nine Mile Point offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. The benefits for Nine
Mile Point are included in the tables below.

We
use a December 31 measurement date for our pension, postretirement, other postemployment, and employee savings plans. The following table summarizes our defined benefit
liabilities and their classification in our Consolidated Balance Sheets:

At December 31,

2008

2007(In millions)Pension benefits

$
936.7

$
385.7Postretirement benefits


415.4


421.5Postemployment benefits


59.9


66.3Total defined benefit obligations


1,412.0


873.5Less: Amount recorded in other current liabilities


57.7


44.9Total noncurrent defined benefit obligations

$
1,354.3

$
828.6


Pension Benefits

We sponsor several defined benefit pension plans for our employees. These include basic qualified plans that most employees
participate in and several non-qualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using
information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.

Sometimes
we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the
benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.

We
fund the qualified plans by contributing at least the minimum amount required under IRS regulations. We calculate the amount of funding using an actuarial method called the projected
unit credit cost method. The assets in all of the plans at December 31, 2008 and 2007 were mostly marketable equity and fixed income securities.

Postretirement Benefits

We sponsor defined benefit postretirement health care and life insurance plans that cover the majority of our employees. Generally,
we calculate the benefits under these plans based on age, years of service, and pension benefit levels or final base pay. We do not fund these plans. For nearly all of the health care plans, retirees
make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.

Effective
in 2002, we amended our postretirement medical plans for all subsidiaries other than Nine Mile Point. Our contributions for retiree medical coverage for future retirees who
were under the age of 55 on January 1, 2002 are capped at the 2002 level. We also amended our plans to increase the Medicare eligible retirees' share of medical costs.

In
2003, the President signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act). This legislation provides a prescription drug benefit for
Medicare beneficiaries, a benefit that we provide to our Medicare eligible retirees. Our actuaries concluded that prescription drug benefits available under our postretirement medical plan are
"actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act. This subsidy reduced our 2008 Accumulated Postretirement Benefit Obligation by $43.3 million
and our 2008 postretirement medical payments by $2.4 million.

Liability Adjustments

At December 31, 2008 and 2007, our pension obligations were greater than the fair value of our plan assets for our qualified
and our nonqualified pension plans as follows:

Qualified PlansNon-Qualified PlansAt December 31, 2008

Nine Mile

Other

Total(In millions)Accumulated benefit obligation

$
123.7

$
1,417.3

$
99.8

$
1,640.8Fair value of assets


63.3


804.3





867.6Unfunded obligation

$
60.4

$
613.0

$
99.8

$
773.2




Qualified PlansAt December 31, 2007

Nine Mile

Other

Non-Qualified
Plans

Total(In millions)Accumulated benefit obligation

$
98.0

$
1,332.2

$
69.7

$
1,499.9Fair value of assets


78.6


1,179.9





1,258.5Unfunded obligation

$
19.4

$
152.3

$
69.7

$
241.4


Effective December 31, 2006, we adopted SFAS No. 158,Employer's Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB Statement No. 87, 106 and 132(R).Under SFAS No. 158, we are required to reflect the funded status of our pension
plans in terms of the projected benefit obligation, which is higher than the accumulated benefit obligation because it includes the impact of expected future compensation increases on the pension
obligation. In addition, SFAS No. 158 requires us to reflect the

123

---



funded
status of our postretirement benefits in terms of the accumulated postretirement benefit obligation.

The
net impact of adopting SFAS No. 158 in 2006 was to increase our pension and postretirement liabilities by $252.2 million, decrease the intangible asset by
$28.6 million, and increase accumulated other comprehensive loss by $280.8 million pre-tax, or $169.5 million after-tax.

The
following table summarizes the impact of SFAS No. 158 adjustments recorded at December 31, 2008 and 2007:

Accumulated Other Comprehensive Income (Loss)Postretirement
Benefit
LiabilityPension
LiabilityDecember 31,

Pre-tax

After-tax(In millions)2008

$
590.7

$
(9.5
)
$
(581.2
)
$
(347.1
)2007

$
3.1

$
(22.5
)
$
19.4

$
11.6


Obligations and Assets

As a result of workforce reduction initiatives, pension and postretirement special termination benefits were recorded in 2008, 2007
and 2006. We discuss the workforce reduction initiatives further inNote 2.

We
show the change in the benefit obligations and plan assets of the pension and postretirement benefit plans in the following tables. Postretirement benefit plan amounts are presented
net of expected reimbursements under Medicare Part D.

Pension
Benefits

Postretirement
Benefits2008

2007

2008

2007(In millions)Change in benefit obligation (1)Benefit obligation at January 1

$
1,644.2

$
1,629.8

$
421.5

$
441.5Service cost


55.4


49.4


6.1


6.5Interest cost


100.2


94.7


24.0


24.4Plan amendments


12.1








Plan participants' contributions








10.8


8.7Actuarial loss (gain)


102.4


(27.6
)

(9.5
)

(22.3
)Special termination benefits


2.2


1.2


0.8


0.3Benefits paid (2)(3)


(112.2
)

(103.3
)

(38.3
)

(37.6
)Benefit obligation at December 31

$
1,804.3

$
1,644.2

$
415.4

$
421.5


Pension
Benefits

Postretirement
Benefits2008

2007

2008

2007(In millions)Change in plan assetsFair value of plan assets at January 1

$
1,258.5

$
1,161.2

$


$
Actual return on plan assets


(364.9
)

71.3





Employer contribution (1)


86.2


129.3


27.5


28.9Plan participants' contributions








10.8


8.7Benefits paid (2)(3)


(112.2
)

(103.3
)

(38.3
)

(37.6
)Fair value of plan assets at December 31

$
867.6

$
1,258.5

$


$



Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income

We show the components of net periodic pension benefit cost in the following table:

Year Ended December 31,

2008

2007

2006(In millions)Components of net periodic pension benefit costService cost

$
55.4

$
49.4

$
49.0Interest cost


100.2


94.7


89.3Expected return on plan assets


(111.3
)

(102.6
)

(96.6
)Amortization of unrecognized prior service cost


10.9


5.2


5.7Recognized net actuarial loss


24.7


32.7


37.3Amount capitalized as construction cost


(10.2
)

(11.7
)

(13.4
)Net periodic pension benefit cost (1)

$
69.7

$
67.7

$
71.3


124

---



We show the components of net periodic postretirement benefit cost in the following table:

Year Ended December 31,

2008

2007

2006(In millions)Components of net periodic postretirement benefit costService cost

$
6.1

$
6.5

$
7.7Interest cost


24.0


24.4


23.7Amortization of transition obligation


2.1


2.1


2.1Recognized net actuarial loss


2.0


4.1


6.6Amortization of unrecognized prior service cost


(3.5
)

(3.5
)

(3.5
)Amount capitalized as construction cost


(7.6
)

(7.7
)

(8.2
)Net periodic postretirement benefit cost (1)

$
23.1

$
25.9

$
28.4


As a result of adopting SFAS No. 158, the following is a summary of amounts we have recorded in "Accumulated other comprehensive income" and of expected
amortization of those amounts over the next twelve months:

Pension
Benefits

Postretirement
BenefitsExpected Amortiz-
ation Next 12 Months2008

2007

2008

2007(In millions)Unrecognized actuarial loss

$
999.8

$
445.9

$
78.7

$
90.2

$
43.3Unrecognized prior service cost


22.5


21.4


(22.6
)

(26.2
)

7.2Unrecognized transition obligation








8.5


10.7


2.1Total

$
1,022.3

$
467.3

$
64.6

$
74.7

$
52.6


Expected Cash Benefit Payments

The pension and postretirement benefits we expect to pay in each of the next five calendar years and in the aggregate for the
subsequent five years are shown below. These estimated benefits are based on the same assumptions used to measure the benefit obligation at December 31, 2008, but include benefits attributable
to estimated future employee service.

Postretirement BenefitsPension
Benefits

Before
Medicare
Part D

Subsidy

After
Medicare
Part D(In millions)2009

$
152.3

$
33.0

$
2.7

$
30.32010


151.6


33.7


2.9


30.82011


118.3


34.3


3.0


31.32012


131.1


34.5


3.2


31.32013


137.7


35.1


3.3


31.82014-2018


807.6


182.3


16.9


165.4


Assumptions

We made the assumptions below to calculate our pension and postretirement benefit obligations and periodic cost.

Pension
Benefits

Postretirement
BenefitsAssumption
Impacts
Calculation of2008

2007

2008

2007Discount rate


6.00
%

6.25
%

6.00
%

6.25
%
Benefit Obligation and Periodic CostExpected return on plan assets


8.75


8.75


N/A


N/A

Periodic CostRate of compensation increase


4.0


4.0


4.0


4.0

Benefit Obligation and Periodic Cost


Our discount rate is based on a bond portfolio analysis of high quality corporate bonds whose maturities match our expected benefit payments. Our
8.75% overall expected long-term rate of return on plan assets reflected our long-term investment strategy in terms of asset mix targets and expected returns for each asset
class for this period. Effective in 2009, we reduced our expected long-term rate of return assumption to 8.50%.

125

---



Annual
health care inflation rate assumptions also impact the calculation of our postretirement benefit obligation and periodic cost. We assumed the following health care inflation rates
to produce average claims by year as shown below:

At December 31,

2008

2007Next year


8.0
%

9.0
%Following year


7.5
%

8.0
%Ultimate trend rate


5.0
%

5.0
%Year ultimate trend rate reached


2015


2014


A one-percentage point increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit
obligation by approximately $25 million as of December 31, 2008 and would increase the combined service and interest costs of the postretirement benefit cost by approximately
$2 million annually.

A
one-percentage point decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately
$21 million as of December 31, 2008 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $2 million annually.

Qualified Pension Plan Assets

The asset allocations for our qualified pension plans were as follows:

At December 31,

2008

2007Equity securities


54
%

62
%Debt securities


35


31Other


11


7Total


100
%

100
%


The category "Other" primarily represents investments in financial limited partnerships. Our long-term pension plan investment strategy is to seek an
asset mix of 58% equity, 30% fixed income, and 12% other investments. We rebalance our portfolio periodically when the sum of equity and other investments differs from 70% by three percentage points
or more, we change an outside investment advisor, or we make contributions to the trust.

We
determine expected return on plan assets using a market-related value of plan assets that recognizes asset gains and losses ratably over a five-year period.

Contributions and Benefit Payments

We contributed $76 million to our qualified pension plans in March 2008, even though there was no IRS required minimum
contribution in 2008. We expect to contribute $218 million to our qualified pension plans in 2009. Our non-qualified pension plans and our postretirement benefit programs are not
funded. We estimate that we will incur approximately $21 million in pension benefits for our non-qualified pension plans and approximately $30 million for retiree health and
life insurance costs net of Medicare Part D during 2009.

Other Postemployment Benefits

We provide the following postemployment benefits:



We
recognized expense associated with our other postemployment benefits of $1.9 million in 2008, $16.7 million in 2007, and $9.6 million in 2006. BGE's portion of
expense associated with other postemployment benefits was $2.2 million in 2008, $10.2 million in 2007, and $5.6 million in 2006.

We
assumed the discount rate for other postemployment benefits to be 5.00% in 2008 and 5.25% in 2007. This assumption impacts the calculation of our other postemployment benefit
obligation and periodic cost.

Employee Savings Plan Benefits

We sponsor defined contribution savings plans that are offered to all eligible employees. The savings plans are qualified 401(k)
plans under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to
participant accounts are made under these plans. Matching contributions to these plans were as follows:

Year Ended December 31,

2008

2007

2006(In millions)Nonregulated businesses

$
17.6

$
16.1

$
14.6BGE


5.8


5.8


5.4Total Constellation Energy

$
23.4

$
21.9

$
20.0


126

---



8Credit Facilities and Short-Term Borrowings

Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one
year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.

Constellation Energy

Constellation Energy had bank and other lines of credit under committed unsecured credit facilities totaling $6.2 billion at
December 31, 2008 for short-term financial needs. We enter into these facilities to ensure adequate liquidity to support our operations. In addition, we had other uncommitted credit
facilities, which had letters of credit of $17 million outstanding at December 31, 2008.

Our
liquidity requirements are funded with credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, which
support direct cash borrowings and the issuance of commercial paper, if available. We also use our credit facilities to support the issuance of letters of credit, primarily for our merchant energy
business.

These
facilities can issue letters of credit, commercial paper, if available, and/or cash borrowings up to approximately $6.2 billion as shown below. As of December 31,
2008, we had $3.6 billion in letters of credit issued and borrowed $485.7 million against those facilities. The weighted-average effective interest rate for this outstanding borrowing
was 0.79% at December 31, 2008. At January 31, 2009, we had $3.5 billion in letters of credit issued and borrowed $1.2 billion against those facilities. We have also
included the pro forma effect on our credit facilities, which are reduced or terminated upon the occurrence of certain events, of closing the transactions contemplated by the Investment Agreement with
EDF, which is expected to occur in the third quarter of 2009:

Facility Expiration

Facility
Size

Facility Size
Upon Completion
of the EDF
Transaction(In billions)July 2012

$
3.85

$
2.32November 2009 (A)


1.23


June 2009 (B)


0.60


September 2013


0.35


December 2009


0.15


Total

$
6.18

$
2.32


BGE

BGE has a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the
banks, use the facility to allow commercial paper to be issued, if available, or issue letters of credit. As of December 31, 2008 and January 31, 2009, BGE had $1.0 million in
letters of credit issued under this facility and borrowed $370.0 million against this facility. The weighted-average effective interest rate for this outstanding borrowing was 1.87% at
December 31, 2008. As of December 31, 2007, BGE had $0.7 million of letters of credit issued under this facility.

In
addition, at December 31, 2008 and January 31, 2009, BGE had no commercial paper outstanding. There was no commercial paper outstanding as of December 31, 2007.

Net Available Liquidity

The following table provides a summary of our net available liquidity at December 31, 2008:

As of December 31, 2008Constellation
Energy

BGE

Total
Consolidated(In billions)Credit facilities

$
6.2

$
0.4

$
6.6Less: Letters of credit issued


(3.6
)




(3.6
)Less: Cash drawn on credit facilities


(0.5
)

(0.4
)

(0.9
)Undrawn facilities


2.1





2.1Less: Commercial paper outstanding








Net available facilities


2.1





2.1Add: Cash


0.2





0.2Net available liquidity

$
2.3

$


$
2.3


127

---



The following table provides our net available liquidity at January 31, 2009:

As of January 31, 2009Constellation
Energy

BGE

Total
Consolidated(In billions)Credit facilities

$
6.2

$
0.4

$
6.6Less: Letters of credit issued


(3.5
)




(3.5
)Less: Cash drawn on credit facilities


(1.2
)

(0.4
)

(1.6
)Undrawn facilities


1.5





1.5Less: Commercial paper outstanding








Net available facilities


1.5





1.5Add: Cash


0.8





0.8Net available liquidity

$
2.3

$


$
2.3


In addition, Constellation Energy had $14.0 million of short-term borrowings outstanding at December 31, 2007 under a
three year $50 million line of credit expiring in 2010 relating to our merchant energy business. The weighted-average effective interest rate for this outstanding borrowing was 7.44% at
December 31, 2007. There were no short-term borrowings outstanding under this line of credit at December 31, 2008.

Other Sources of Liquidity

In December 2008, we executed an Investment Agreement with EDF that includes an asset put arrangement that provides us with an option
at any time through December 31, 2010 (or the termination of the Investment Agreement by EDF if we breach that agreement) to sell certain non-nuclear generation assets, at
pre-agreed prices, to EDF for aggregate proceeds of no more than $2 billion pre-tax, or approximately $1.4 billion after-tax. Exercise of the put
option is conditioned upon the receipt of regulatory approvals and third-party consents, the absence of any material liens on such assets, and the absence of a material adverse effect, as defined in
the Investment Agreement.

Also,
EDF has provided us with a $600 million interim backstop liquidity facility, included in the Constellation Energy credit facilities disclosed on the prior page. In order to
use this facility, we will need to certify to EDF that there is no availability for additional
borrowings under any of our other existing credit facilities and that we have used our best effort to obtain financing from any other source on reasonable terms and have not been able to obtain such
financing. This facility expires on the earliest of:



We
are actively seeking to increase available liquidity and to reduce our business risk. Specifically, we are reducing capital spending and ongoing expenses, scaling down the expected
variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. During 2008, we
sold certain of our upstream gas properties and in 2009, we made progress on several other initiatives as discussed in more detail inNote 3.

Currently,
we have certain agreements that contain provisions that would require a significant amount of additional collateral upon a credit rating downgrade. By the successful execution
of the announced divestitures, we would expect a significant return of currently posted collateral and a reduction in our downgrade collateral requirements, subject to changes in commodity prices.

We
believe that we will have sufficient liquidity to meet our ongoing requirements over the next 12 months. However, our liquidity projections include assumptions for commodity
price changes, which are subject to significant volatility, and continued changes in our business operations resulting from our strategic initiatives. Also, we are exposed to certain operational risks
that could have a significant impact on our liquidity. In addition, if we cannot successfully execute on our strategies, our available liquidity would be negatively affected, which would have a
material adverse effect on our results of operations and financial condition.

Credit Facility Compliance and Covenants

The credit facilities of Constellation Energy and BGE have limited material adverse change clauses, none of which would prohibit
draws under the existing facilities.

Certain
credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At
December 31, 2008, the debt to capitalization ratio as defined in the credit agreements was 57%.

Under
our $3.85 billion and $1.23 billion credit facilities, we will be required to grant a lien on certain of our generating facilities and pledge our ownership interests
in our nuclear business to the lenders if the Investment Agreement with EDF has closed or been terminated and our Standard & Poors or Fitch senior unsecured debt credit rating is below
BBB- or our Moody's senior unsecured debt credit rating is below Baa3.

Our
$1.23 billion credit facility requires us to maintain consolidated earnings before interest, taxes, depreciation, and amortization to consolidated interest expense ratio of at
least 2.75 when our Standard & Poors Rating Group senior unsecured debt rating is BBB- or lower and our Moody's Investors Service senior unsecured debt rating is Baa3 or lower.

The
credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2008, the debt to
capitalization ratio for BGE as defined in this credit agreement was 55%.

128

---



9Capitalization

We
detail in the table below our total capitalization, which includes long-term debt, common stock, and preference stock, as of December 31, 2008 and 2007.

At December 31,

2008

2007(In millions)Long-Term DebtLong-term debt of Constellation EnergyZero Coupon Senior Notes, due June 19, 2023

$
256.7

$
8.625% Series A Junior Subordinated Debentures, due June 15, 2063


450.0


8% Series B Mandatorily Redeemable Preferred Stock


1,000.0


14% Senior Notes, due December 31, 2009


1,000.0


6.125% Fixed-Rate Notes, due September 1, 2009


500.0


500.07.00% Fixed-Rate Notes, due April 1, 2012


700.0


700.04.55% Fixed-Rate Notes, due June 15, 2015


550.0


550.07.60% Fixed-Rate Notes, due April 1, 2032


700.0


700.0Fair Value of Interest Rate Swaps


55.9


11.8Total long-term debt of Constellation Energy


5,212.6


2,461.8Long-term debt of nonregulated businessesTax-exempt debt transferred from BGE effective July 1, 2000Pollution control loan, due July 1, 2011





36.0Port facilities loan, due June 1, 2013


10.0


48.04.10% Pollution control loan, due July 1, 2014


20.0


20.0Economic development loan, due December 1, 2018





35.0Floating-rate pollution control loan, due June 1, 2027


8.8


8.8Tax-exempt variable rate notes, due April 1, 2024


75.0


75.0Tax-exempt variable rate notes, due December 1, 2025


47.0


47.0Tax-exempt variable rate notes, due December 1, 2037


65.0


65.0District Cooling facilities loan, due December 1, 2031


25.0


25.05.00% Mortgage note, due June 15, 2010


1.6


3.64.25% Mortgage note, due March 15, 2009


0.2


0.87.3% Fixed Rate Note, due June 1, 2012


1.8


1.8South Carolina synthetic fuel facility loan, due January 15, 2008 (imputed interest rate of 3.47%)





3.0Total long-term debt of nonregulated businesses


254.4


369.0First Refunding Mortgage Bonds of BGE6.625% Series, due March 15, 2008





119.7Total First Refunding Mortgage Bonds of BGE





119.7Other long-term debt of BGE6.125% Notes, due July 1, 2013


400.0


5.90% Notes, due October 1, 2016


300.0


300.05.20% Notes, due June 15, 2033


200.0


200.06.35% Notes, due October 1, 2036


400.0


400.0Medium-term notes, Series E


143.0


174.5Medium-term notes, Series G





140.0Total other long-term debt of BGE


1,443.0


1,214.56.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred
securities


257.7


257.7Rate stabilization bonds


564.4


623.2Unamortized discount and premium


(41.9
)

(4.8
)Current portion of long-term debt


(2,591.5
)

(380.6
)Total long-term debt

$
5,098.7

$
4,660.5


129

---



At December 31,

2008

2007(In millions)Minority Interests(1)

$
20.1

$
19.2BGE Preference StockCumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at
$101.78 per share until June 30, 2009, and at lesser amounts thereafter


40.0


40.06.97%, 1993 Series, 500,000 shares outstanding, callable at $101.74 per share until September 30, 2009, and at lesser amounts thereafter


50.0


50.06.70%, 1993 Series, 400,000 shares outstanding, callable at $101.68 per share until December 31, 2009, and at lesser amounts thereafter


40.0


40.06.99%, 1995 Series, 600,000 shares outstanding, callable at $102.45 per share until September 30, 2009, and at lesser amounts thereafter


60.0


60.0Total BGE preference stock not subject to mandatory redemption


190.0


190.0Common Shareholders' EquityCommon stock without par value, 600,000,000 shares authorized; 199,128,908 and 178,437,208 shares issued and outstanding at December 31, 2008 and
2007, respectively. (At December 31, 2008, 8,729,667 shares were reserved for the long-term incentive plans, and 1,508,553 shares were reserved for the employee savings plan.)


3,164.5


2,513.3Retained earnings


2,228.7


3,919.5Accumulated other comprehensive loss


(2,211.8
)

(1,092.6
)Total common shareholders' equity


3,181.4


5,340.2Total Capitalization

$
8,490.2

$
10,209.9


Long-term Debt

Long-term debt matures in one year or more from the date of issuance. The long-term debt of Constellation Energy and BGE
do not contain material adverse change clauses. We detail our long-term debt in the table above.

Constellation Energy

In June 2008, we closed on the following transactions:



In
connection with this offering, Constellation Energy executed a replacement capital covenant (RCC) for the benefit of holders of Constellation Energy's 7.60% Notes due April 1,
2032. Under the terms of the RCC, Constellation Energy may not redeem, purchase or defease any subordinated debentures on or before June 15, 2033, or, if the maturity date is extended, the date
which is 30 years prior to the maturity date of the subordinated debentures (but not later than June 15, 2038), unless a specified amount of qualifying securities are issued to
non-affiliates in a replacement offering during the 180 days prior to the redemption, purchase or defeasance date. Qualifying securities include those that have
equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the subordinated debentures at the time of redemption, purchase or
defeasance.

Mandatorily Redeemable Series B Preferred Stock

On December 17, 2008, Constellation Energy entered into an Investment Agreement with EDF. We discuss the Investment Agreement in more detail in Note 15. Simultaneously with the
execution of the Investment Agreement, Constellation Energy issued 10,000 shares of 8% Series B Preferred
Stock (Series B Preferred Stock) to EDF for $1 billion, which was restricted for

130

---



the
repayment of our 14% Senior Notes. If EDF completes the purchase of the 49.99% interest in our nuclear generation and operation business pursuant to the Investment Agreement, at the closing of
that acquisition EDF will surrender to Constellation Energy all of the shares of the Series B Preferred Stock as partial payment for the purchase of the interest in our nuclear generation and
operation business. As discussed inNote 15, we expect the transaction to close and the Series B Preferred Stock to be redeemed by the
third quarter of 2009.

Because
of the mandatory redemption provision, we accounted for the Series B Preferred Stock as debt and included it in the "Current portion of long-term debt" line on
our Consolidated Balance Sheets. We report dividends in the "Interest expense" line on our Consolidated Statements of Income (Loss).

If
the Investment Agreement is terminated, the Series B Preferred Stock will be redeemed at the later of the date of termination or December 31, 2009 for $1 billion
aggregate principal amount of 10% Senior Notes of Constellation Energy due June 30, 2010.

So
long as any shares of the Series B Preferred Stock are outstanding, Constellation Energy and its subsidiaries may not, without the consent of holders of at least a majority of
then outstanding shares of the Series B Preferred Stock, undertake certain actions. Such actions include amending or revising our organizational documents, issuing equity senior or equal to the
Series B Preferred Stock, authorizing a liquidation, incurring certain types of indebtedness, paying certain dividends, redeeming or repurchasing shares of capital stock, and entering into
affiliate transactions.

The
terms of the Series B Preferred Stock allow us to issue debt without the consent of the holders of the majority of the Series B Preferred Stock only if, after issuance
of such debt, we maintain a ratio of debt to capitalization equal to or less than 65%.

Mandatorily Redeemable Series A Convertible Preferred Stock

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican and, on December 17, 2008,
Constellation Energy and MidAmerican mutually agreed to terminate the merger agreement. We discuss the termination of the merger agreement in more detail in Note 15. In connection with the merger
agreement, Constellation Energy issued 10,000 shares of 8% Series A Convertible Preferred Stock
(Series A Preferred Stock) to MidAmerican for $1 billion.

Upon
termination of the merger agreement, the Series A Preferred Stock converted into $1 billion aggregate principal amount of 14% Senior Notes of Constellation Energy and
the right for MidAmerican to receive the equivalent of 19.9% of the outstanding common shares. However, since regulatory approval to issue all of the required outstanding common shares was not
received, in accordance with the terms of the Series A Preferred Stock, Constellation Energy issued the following to MidAmerican:



The
Senior Notes were repaid in full on January 12, 2009 together with accrued and unpaid interest through that date of approximately $5 million.

BGE

BGE's First Refunding Mortgage Bonds

We paid in full the last series of BGE's first refunding mortgage bonds outstanding in March 2008. These bonds were secured by a mortgage lien on all
of BGE's assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also were subject to the lien of BGE's mortgage, along with the stock of Safe Harbor Water Power
Corporation and Constellation Enterprises, Inc. The assets were released from this lien following the discharge of the mortgage in October 2008.

BGE's Rate Stabilization Bonds

In June 2007, BondCo, a subsidiary of BGE, issued an aggregate principal amount of $623.2 million of rate stabilization bonds to recover
deferred power purchase costs. We discuss BondCo in more detail inNote 4. Below are the details of the rate stabilization bonds at
December 31, 2008:

Principal

Interest Rate

Scheduled
Maturity Date$225.2


5.47
%
October 2012220.0


5.72

April 2016119.2


5.82

April 2017


The bonds are secured primarily by a usage-based, non-bypassable charge payable by all of BGE's residential electric customers over a ten year period.
The charges will be adjusted semi-annually to ensure that the aggregate charges collected are sufficient to pay principal and interest on the bonds, as well as certain on-going
costs of administering and servicing the bonds. BondCo cannot use the charges collected to satisfy any other obligations. BondCo's assets are not assets of any affiliate and are not available to pay
creditors of any affiliate of BondCo. If BondCo is unable to make principal and interest payments on the bonds, neither Constellation Energy, nor BGE, are required to make the payments on behalf of
BondCo.

131

---



BGE's Other Long-Term Debt

In June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013. Interest is payable semi-annually on
January 1 and July 1, beginning January 1, 2009.

On
July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energy business related to the transferred generating assets. At
December 31, 2008, BGE remains contingently liable for the $38.8 million outstanding balance of this debt.

BGE's
fixed-rate medium-term note, series E, outstanding at December 31, 2008 has a weighted average interest rate of 6.72%, maturing between 2009
and 2012.

BGE Deferrable Interest Subordinated Debentures

On November 21, 2003, BGE Capital Trust II (BGE Trust II), a Delaware statutory trust established by BGE, issued 10,000,000
Trust Preferred Securities for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 6.20%.

BGE
Trust II used the net proceeds from the issuance of common securities to BGE and the Trust Preferred Securities to purchase a series of 6.20% Deferrable Interest Subordinated
Debentures due October 15, 2043 (6.20% debentures) from BGE in the aggregate
principal amount of $257.7 million with the same terms as the Trust Preferred Securities. BGE Trust II must redeem the Trust Preferred Securities at $25 per preferred security plus
accrued but unpaid distributions when the 6.20% debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the 6.20% debentures at any time on or after
November 21, 2008 or at any time when certain tax or other events occur.

BGE
Trust II will use the interest paid on the 6.20% debentures to make distributions on the Trust Preferred Securities. The 6.20% debentures are the only assets of BGE
Trust II.

BGE
fully and unconditionally guarantees the Trust Preferred Securities based on its various obligations relating to the trust agreement, indentures, 6.20% debentures, and the preferred
security guarantee agreement.

For
the payment of dividends and in the event of liquidation of BGE, the 6.20% debentures are ranked prior to preference stock and common stock.

Revolving Credit Agreement

On December 18, 2001, BGE's subsidiary, District Chilled Water Partnership (ComfortLink) entered into a $25.0 million loan agreement
with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to
finance the cost of building a chilled water distribution system. The interest rate on this debt resets weekly. These bonds, and the corresponding loan, can be redeemed at any time at par plus accrued
interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option.

Maturities of Long-Term Debt

Our long-term borrowings mature on the following schedule:

Year

Constellation
Energy

Nonregulated
Businesses

BGE

Total(In millions)2009

$
2,500.0

$
1.5

$
65.0

$
2,566.52010





0.4


56.5


56.92011





0.1


81.7


81.82012


723.2


1.6


172.5


897.32013





10.0


466.6


476.6Thereafter


2,430.4


240.8


1,422.8


4,094.0Total

$
5,653.6

$
254.4

$
2,265.1

$
8,173.1


The table above includes $697.7 million of principal for the Zero Coupon Senior Notes, assuming the notes are not redeemed prior to June 19, 2023
and the original issue discount accrues until redemption. In addition, at December 31, 2008, we had long-term loans totaling $250.8 million that mature after 2008, which are
periodically remarketed and could require repayment prior to maturity following any unsuccessful remarketing. At December 31, 2008, $25.0 million is classified as current portion of
long-term debt at BGE.

During
2008, several of these long-term loans were unable to be remarketed. As a result, at December 31, 2008, we had repurchased $109.0 million of these loans.
In January 2009, $109.0 million of these long-term loans that had previously been repurchased were subsequently remarketed. In February 2009, we decided to no longer attempt to
remarket certain tax-exempt debt as we may retire this debt. As a result, we held $97 million of this debt during February 2009 and expect to hold an additional $22 million of this debt
in March 2009.

Weighted-Average Interest Rates for Variable Rate Debt

Our weighted-average interest rates for variable rate debt outstanding were:

At December 31,

2008

2007Nonregulated Businesses (including Constellation Energy)Loans under credit agreements


2.61
%

3.77
%Tax-exempt debt


3.17
%

3.53
%Fixed-rate debt converted to floating *


4.88
%

6.43
%


Preference Stock

Each series of BGE preference stock has no voting power, except for the following:



132

---





Common Stock

Issuances

When the merger agreement with MidAmerican was terminated, the Series A Preferred Stock converted into $1 billion aggregate principal
amount of 14% Senior Notes of Constellation Energy and the right for MidAmerican to receive 19.9% of the outstanding common shares. However, since regulatory approval to issue all of the required
outstanding common shares was not received, we were only able to issue 19,897,322 shares of our common stock (equivalent to 9.9% of the outstanding common shares).

As
provided by the terms of the Series A Preferred Stock, we paid MidAmerican cash of $418.2 million for the portion of common shares that could not be issued.

Share Repurchase Program

In October 2007, our Board of Directors approved a common share repurchase program for up to $1 billion of our outstanding common shares.
Subsequent to this approval, on October 31, 2007, we entered into an accelerated share repurchase agreement with a financial institution to repurchase a total of $250.0 million, and, on
November 2, 2007, we purchased 2,023,527 of outstanding shares of our common stock, which represents the minimum number of shares deliverable under the agreement, for a total of
$187.5 million.

We
accounted for the accelerated share repurchase agreement as two separate transactions: as shares of common stock acquired at cost and a forward contract indexed to our own common
stock. We accounted for the shares of common stock repurchased in November 2007 as a reduction to common shareholders' equity at cost. We accounted for the forward contract as a component of common
shareholders' equity at fair value, which totaled $62.5 million at inception. The forward contract was settled on January 23, 2008 based on a discount to the volume-weighted average
trading price of our common stock during that period. As a result, the financial institution delivered 514,376 additional shares to us to complete the transaction.

We
did not repurchase any shares under this program during 2008. Pursuant to the terms of our Series B Preferred Stock, we are prohibited from engaging in a common share
repurchase in an aggregate amount in excess of $100 million without the approval of the holders of more than 50% of the then outstanding shares of Series B Preferred Stock.

133

---



10Taxes

The
components of income tax expense are as follows:

Year Ended December 31,

2008

2007

2006(Dollar amounts in millions)Income TaxesCurrentFederal

$
2.8

$
168.2

$
246.3State


48.1


40.6


37.2Current taxes charged to expense


50.9


208.8


283.5DeferredFederal


(101.6
)

184.7


50.7State


(21.2
)

41.5


23.7Deferred taxes (credited) charged to expense


(122.8
)

226.2


74.4Investment tax credit adjustments


(6.4
)

(6.7
)

(6.9
)Income taxes per Consolidated Statements of Income (Loss)

$
(78.3
)
$
428.3

$
351.0


Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income
taxes as follows:

Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes(Loss) Income from continuing operations before income taxes (excluding BGE preference stock dividends)

$
(1,379.5
)
$
1,263.9

$
1,112.8Statutory federal income tax rate


35
%

35
%

35
%Income taxes computed at statutory federal rate


(482.8
)

442.4


389.5Increases (decreases) in income taxes due toDepreciation differences not normalized on regulated activities


3.3


3.7


3.6Amortization of deferred investment tax credits


(6.4
)

(6.7
)

(6.9
)Synthetic fuel tax credits flowed through to income


(4.5
)

(166.2
)

(120.2
)Estimated synthetic fuel tax credit phase-out





110.3


44.3Interest expense on mandatorily redeemable preferred stock


7.8





Qualified decommissioning impairment loss


(28.5
)




State income taxes, net of federal income tax benefit


17.3


53.4


42.6Merger-related transaction costs


416.2





(5.3
)Other


(0.7
)

(8.6
)

3.4Total income taxes

$
(78.3
)
$
428.3

$
351.0Effective income tax rate


5.7
%

33.9
%

31.5
%


State income tax expense recorded in 2008 reflects the impact of an increase in the State of Maryland corporate tax rate from 7% to 8.25% effective
January 1, 2008 that was enacted into law on November 19, 2007. In accordance with SFAS No. 109,Accounting for Income Taxes, in
2007 we recognized a $0.7 million after-tax charge for the net impact of the changes in the Maryland tax rate on deferred income tax assets and liabilities. The impact of the
Maryland tax rate change on BGE is discussed below.

BGE's
effective tax rate was 28.7% in 2008, 40.7% in 2007, and 37.5% in 2006. In general, the primary difference between BGE's effective tax rate and the 35% statutory federal income tax
rate for all years relates to Maryland corporate income taxes, net of the related federal income tax benefit. The decrease in BGE's effective tax rate in 2008 is due to lower taxable income related to
the Maryland settlement agreement, which increased the relative percentage impact of favorable permanent tax adjustments on BGE's effective tax rate. BGE's after-tax effective state rate
of 7.6% for 2007 includes an adjustment of deferred income tax liabilities to reflect the November 19, 2007 enactment into law of a change in the Maryland corporate income tax rate, as
discussed above. In 2006, BGE's effective tax rate includes the benefit of merger-related costs incurred in 2005 that were deductible in 2006 as a result of the termination of the merger with FPL
Group (0.5%) and a deduction for dividends paid to the employee savings plan (0.5%).

134

---



The
major components of our net deferred income tax liability are as follows:

Constellation Energy

BGEAt December 31,

2008

2007

2008

2007(In millions)Deferred Income TaxesDeferred tax liabilitiesNet property, plant and equipment

$
1,432.5

$
1,570.7

$
604.4

$
583.8Qualified nuclear decommissioning trust funds


310.9


360.3





Regulatory assets, net


295.5


312.0


295.5


312.0Derivative assets and liabilities, net


310.6


217.8





Other


126.6


122.6


32.5


12.2Total deferred tax liabilities


2,476.1


2,583.4


932.4


908.0Deferred tax assetsAsset retirement obligation


391.6


368.3





Defined benefit obligations


552.0


362.0


30.8


61.6Financial investments and hedging instruments


949.7


426.1





Deferred investment tax credits


17.8


20.4


4.3


4.8Other


156.0


118.8


13.8


11.9Total deferred tax assets


2,067.1


1,295.6


48.9


78.3Total deferred tax liability, net


409.0


1,287.8


883.5


829.7Less: Current portion of deferred tax (asset)/liability


(268.0
)

(300.7
)

40.2


44.1Long-term portion of deferred tax liability, net

$
677.0

$
1,588.5

$
843.3

$
785.6


Synthetic Fuel Tax Credits

Through December 31, 2007, our merchant energy business owned interests in several synthetic fuel facilities that manufactured
solid synthetic fuel produced from coal as defined under the Internal Revenue Code (IRC) for which we could claim tax credits on our Federal income tax return. The synthetic fuel process involves
combining coal material with a chemical reagent to create a significant chemical change. We requested and received private letter rulings from the IRS that the synthetic fuel produced from these
facilities produced a significant chemical change and thus qualified for synthetic fuel tax credits. To date, the IRS has not disallowed any of the synthetic fuel tax credits from these facilities.

The
IRC provided for a phase-out of synthetic fuel tax credits if average annual wellhead oil prices increased above certain levels. Based on these provisions, we recorded a
70% tax credit phase-out as a reduction in tax credits of $110.3 million during 2007. We did not record any synthetic fuel tax credits in 2008 as a result of the expiration of the
availability of the tax credits in 2007 and the decommissioning of these facilities in 2008. We did, however, record an additional tax credit true-up adjustment of $4.5 million
during 2008 related to our estimate of the 2007 tax credit phase-out.

Income Tax Audits

We file income tax returns in the United States and foreign jurisdictions. With few exceptions, we are no longer subject to U.S.
federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. In 2008, the IRS examination of our consolidated federal income tax returns for
the tax years 2002 through 2004 was settled and the federal statute of limitations for those years is scheduled to expire on April 15, 2009. In addition, in 2008 the IRS initiated an audit of
our consolidated federal income tax returns for the tax years 2005 through 2007. Although the final outcome of the 2005-2007 IRS audit and future tax audits is uncertain, we believe that
adequate provisions for income taxes have been made for potential liabilities resulting from such matters.

135

---



Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during 2008 and 2007 and our total unrecognized tax benefits
at December 31, 2008 and 2007:

2008

2007(In millions)Total unrecognized tax benefits, January 1

$
114.5

$
104.0Increases in tax positions related to the current year


112.2


13.3Increases in tax positions related to prior years





3.8Reductions in tax positions related to prior years


(15.5
)

(6.0
)Reductions in tax positions related to audit settlements


(21.5
)

Reductions in tax positions as a result of a lapse of the applicable statute of limitations





(0.6
)Total unrecognized tax benefits, December 31 (1)

$
189.7

$
114.5


Increases
in current year tax positions in 2008 are primarily due to unrecognized tax benefits of $93.6 million related to certain MidAmerican merger termination payments and
related transaction fees that were expensed for financial accounting purposes and are expected to be deducted on our 2008 federal and state income tax returns. Other increases in current year tax
positions include unrecognized tax benefits for repair and depreciation deductions measured at amounts consistent with prior IRS examination results and state income tax accruals.

In
April 2008, we received a closing agreement from the State of Hawaii regarding audit examinations for the tax years 2001-2003. Additionally, in June 2008, we received
notice that the United States Congressional Joint Committee on Taxation had approved the results of the IRS examination of our federal consolidated income tax returns for the 2002-2004 tax
years. We reduced our liability for unrecognized tax benefits by $21.5 million to reflect the results of these audits. The impact of the audit settlements on income tax expense was immaterial.

Total
unrecognized tax benefits as of December 31, 2008 of $189.7 million include outstanding state refund claims of approximately $48.3 million for which no tax
benefit was recorded on our Consolidated Balance Sheets because refunds were not received and the claims do not meet the "more-likely-than-not" threshold.

If
the total amount of unrecognized tax benefits of $189.7 million were ultimately realized, our income tax expense would decrease by approximately $159 million. However,
the $159 million includes state tax refund claims of approximately $48 million discussed above that have been disallowed by tax authorities and we believe that there is a remote
likelihood of ultimately realizing any benefit from these refund claim amounts. These state refund claims may be resolved by December 31, 2009. For this reason, we believe it is reasonably
possible that reductions to our total unrecognized tax benefits in the range of $40 to $50 million may occur by December 31, 2009, although these reductions are not expected to
materially impact income tax expense.

Interest
and penalties recorded in our Consolidated Statements of Income (Loss) as tax (benefit) expense relating to liabilities for unrecognized tax benefits were as follows:

For the Year Ended December 31,2008

2007(In millions)Interest and penalties recorded as tax (benefit) expense

$
(0.4
)
$
4.7


BGE's portion of interest and penalties was immaterial for both years.

Accrued interest and penalties recognized in our Consolidated Balance Sheets were $10.3 million, of which BGE's portion was $0.7 million at
December 31, 2008, and $16.8 million, of which BGE's portion was $5.3 million, at December 31, 2007.

136

---



11Leases

There are two types of leasesoperating and capital. Capital leases qualify as sales or purchases of property and are reported in our Consolidated
Balance Sheets. Our capital leases are not material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income (Loss). We expense all lease payments
associated with our regulated business. Lease expense and future minimum payments for long-term, noncancelable, operating leases are not material to BGE's financial results. We present
information about our operating leases below.

Outgoing Lease Payments

We, as lessee, lease certain facilities and equipment. The lease agreements expire on various dates and have various renewal options.
We also enter into certain power purchase agreements which are accounted for as operating leases. Under these agreements, we are required to make fixed capacity payments, as well as variable payments
based on actual output of the plants. We record these payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss). We exclude from our future minimum lease
payments table the variable payments related to the output of the plant due to the contingency associated with these payments.

We
also enter into time charter purchase agreements which entitle us to the use of dry bulk freight vessels in the management of our global coal and logistics services. Certain of these
contracts must be accounted for as leases. During 2008 and 2007, we entered into time charter leases with terms ranging in duration from 1 to 60 months. These arrangements do not include
provisions for material rent increases and do not have provisions for rent holidays, contingent rentals or other incentives. In 2008 and 2007, we recognized aggregate lease expense of approximately
$477 million and $535 million, respectively, related to 49 and 65 dry bulk freight vessels, respectively, hired under time charter arrangements. The average term of these arrangements is
approximately 4 months. We record the payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss).

We
recognized expense related to our operating leases as follows:

Fuel and
purchased
energy expenses

Operating
expenses

Total(In millions)2008

$
664.8

$
25.4

$
690.22007


758.7


28.2


786.92006


162.6


24.7


187.3


At December 31, 2008, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

Year

Power
Purchase
Agreements

Other

Total(In millions)2009

$
288.7

$
26.1

$
314.82010


218.7


22.6


241.32011


206.8


21.4


228.22012


192.5


19.4


211.92013


175.3


18.2


193.5Thereafter


505.6


85.8


591.4Total future minimum lease payments

$
1,587.6

$
193.5

$
1,781.1


Sub-Lease Arrangements

We provide time charters of dry bulk freight vessels as part of the logistical services provided to our global customers that qualify
as sub-leases of our time charter purchase contracts. In 2008 and 2007, we recorded sub-lease income of approximately $289 million and $214 million, respectively,
related to our time charter sub-leases. We did not have any material sub-lease income for 2006. We record sub-lease income as part of "Nonregulated revenues" in our
Consolidated Statements of Income (Loss). As of December 31, 2008, the future minimum rentals to be received for these time charters is shown below:

Year

Time
Charter
Sub-Leases(In millions)2009

$
51.42010


21.52011


9.82012


9.82013


9.8Thereafter


48.2Total future minimum lease rentals

$
150.5


137

---



12Commitments, Guarantees, and Contingencies

Commitments

We have made substantial commitments in connection with our merchant energy, regulated electric and gas, and other nonregulated
businesses. These commitments relate to:



Our
merchant energy business enters into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our
contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2009 and 2028. In addition, our merchant
energy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts
expire in various years between 2009 and 2030.

Our
merchant energy business also has committed to long-term service agreements and other purchase commitments for our plants.

Our
regulated electric business enters into various long-term contracts for the procurement of electricity. These contracts expire during 2009, 2010, and 2011, representing
100% of our estimated requirements until September 2009, approximately 75% of our estimated requirements from October 2009 to May 2010, approximately 50% of our estimated requirements from June 2010
to September 2010, and approximately 25% of our estimated requirements from October 2010 to May 2011. These contracts are recoverable under the Provider of Last Resort agreement reached with the
Maryland PSC and, therefore, are excluded from the following table.

Our
regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement
contracts that expire between 2009 and 2011, and transportation and storage contracts that expire between 2012 and 2027. These contracts are recoverable under BGE's gas cost adjustment clause
discussed inNote 1,and therefore are excluded from the table later in this Note.

Our
other nonregulated businesses have committed to gas purchases and to contributions of additional capital for construction programs and joint ventures in which they have an interest.

We
have also committed to long-term service agreements and other obligations related to our information technology systems.

At
December 31, 2008, we estimate our future obligations to be as follows:

Payments2009

2010-
2011

2012-
2013

Thereafter

Total(In millions)Merchant Energy:Purchased capacity and energy

$
588.4

$
282.2

$
187.5

$
227.3

$
1,285.4Fuel and transportation


1,648.5


1,531.4


718.0


1,292.2


5,190.1Long-term service agreements, capital, and other


190.7


60.2


28.7


18.0


297.6Total merchant energy


2,427.6


1,873.8


934.2


1,537.5


6,773.1Corporate and Other:Long-term service agreements, capital, and other


61.5


3.7








65.2Regulated:Purchase obligations and other


16.9


23.9


11.9


11.3


64.0Total future obligations

$
2,506.0

$
1,901.4

$
946.1

$
1,548.8

$
6,902.3


Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter
into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2019 and provide for the sale
of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power plants extend for terms into 2016 and provide for the sale of all or a
portion of the actual output of certain of our power plants. Substantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the
time of execution.

Guarantees

Our guarantees do not represent incremental Constellation Energy obligations; rather they primarily represent parental guarantees of
subsidiary obligations. The following table summarizes the maximum exposure by guarantor based on the stated limit of our outstanding guarantees:

At December 31, 2008

Stated Limit(In billions)Constellation Energy guarantees

$
16.04Merchant energy business guarantees


0.07BGE guarantees


0.25Total guarantees

$
16.36


138

---



At December 31, 2008, Constellation Energy had a total of $16.36 billion in guarantees in outstanding related to loans, credit facilities, and
contractual performance of certain of its subsidiaries as described below.



Contingencies

Environmental Matters

Solid and Hazardous Waste

The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the clean-up
of certain environmentally contaminated sites. We cannot estimate the final clean-up costs for all of these sites, but the current estimated costs for, and current status of, each site is
described in more detail below.

68th Street Dump

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, which is its list of
sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially liable parties at the site. In March 2004, we and
other potentially responsible parties formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under
the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the potentially responsible parties, including BGE, with respect to investigation of the site became
effective. The settlement requires the potentially responsible parties, over the course of several years, to identify contamination at the site and recommend clean-up options. BGE is fully
indemnified by a wholly-owned subsidiary of Constellation Energy for costs related to this settlement, as well as any clean-up costs. The clean-up costs will not be known until
the investigation is closer to completion. However, those costs could have a material effect on our financial results.

Spring Gardens

In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for
contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on remedial action plans and cost
modeling performed in late 2006, BGE estimates its probable clean-up costs will total $43 million. BGE has recorded these costs as a liability in its Consolidated Balance Sheets and
has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably
possible that additional costs could exceed the amount BGE has recognized by approximately $3 million. Through December 31, 2008, BGE has spent approximately $41 million for
remediation at this site. We do not expect the remaining clean-up costs to have a material effect on our financial results.

BGE
also has investigated other small sites where gas was manufactured in the past. We do not expect the clean-up costs of the remaining smaller sites to have a material
effect on our financial results.

Air Quality

In late July 2005, we received two Notices of Violation (NOVs) from the Placer County Air Pollution Control District, Placer County California
(District) alleging that the Rio Bravo Rocklin facility located in Lincoln, California had violated certain District air emission regulations between January 2003 and March 2005. We have a combined
50% ownership interest in the partnership which owns the Rio Bravo Rocklin facility. In July 2008, the partnership settled the allegations by agreeing to pay approximately $242,000, of which our share
is $121,000, and to implement supplemental environmental projects at the facility over the next 18 months.

In
May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment to resolve alleged violations of air quality opacity
standards at three fossil fuel plants in Maryland. The consent decree requires the subsidiary to pay a $100,000 penalty, provide $100,000 to a supplemental environmental project, and install
technology to control emissions from those plants.

In
January 2009, the EPA issued a NOV to a subsidiary of Constellation Energy, as well as the other owners and the operator of the Keystone coal-fired power plant in
Shelocta, Pennsylvania. We hold an approximately 21% interest in the Keystone plant. The NOV alleges that the plant performed various capital projects beginning in 1984 without complying with the new
source review permitting requirements of the

139

---



Clean
Air Act. The EPA also contends that the alleged failure to comply with those requirements are continuing violations under the plant's air permits. The EPA could seek civil penalties under the
Clean Air Act for the alleged violations.

The
owners and operator of the Keystone plant are investigating the allegations and have entered into discussions with the EPA. We believe there are meritorious defenses to the
allegations contained in the NOV. However, we cannot predict the outcome of this proceeding and it is not possible to determine our actual liability, if any, at this time.

Water Quality

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to
groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a
$1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and
monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately $7.9 million, which includes the $1 million penalty and our estimate of
probable costs to remediate contamination, replace drinking water supplies, monitor groundwater conditions, and otherwise comply with the consent decree. We have paid approximately $2.5 million
of these costs as of December 31, 2008, resulting in a remaining liability at December 31, 2008 of $5.4 million. We estimate that it is reasonably possible that we could incur
additional costs of up to approximately $10 million more than the liability that we accrued.

In
November 2007, a class action complaint was filed in Baltimore City Circuit Court alleging that the subsidiary's ash placement operations at the third party site damaged surrounding
properties. The complaint seeks injunctive and remedial relief relating to the alleged contamination, unspecified compensatory damages for any personal injuries and property damages associated with
the alleged contamination, and unspecified punitive damages. In September 2008, we entered into a non-binding agreement with representatives for the class action plaintiffs and, as a
result, recorded a liability for the anticipated settlement. On October 31, 2008, we entered into a definitive settlement agreement which was approved by the Court in December 2008.

Litigation

In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

Merger with MidAmerican

Beginning September 18, 2008, seven shareholders of Constellation Energy filed lawsuits in the Circuit Court for Baltimore City, Maryland
challenging the then pending merger with MidAmerican. Four similar suits were filed by other shareholders of Constellation Energy in the United States District Court for the District of Maryland.

The
lawsuits claim that the merger consideration was inadequate and did not maximize value for shareholders, that the sales process leading up to the merger was unreasonably short and
procedurally flawed, and that unreasonable deal protection devices were agreed to that ward off competing bids and coerce shareholders into accepting the merger. The federal lawsuits also assert that
the conversion of the Preferred Stock issued to MidAmerican into debt is not permitted under Maryland law. The lawsuits seek declaratory judgments establishing the unenforceability of the merger based
on the alleged breaches of duty, injunctive relief to enjoin the merger, rescission of the merger or rescissory damages, the imposition of a constructive trust in favor of shareholders of any benefits
received by the individual members of the Board of Directors of Constellation Energy, and reasonable costs and expenses, including attorney's fees.

The
termination of the MidAmerican merger renders moot the claims attempting to enjoin the merger with MidAmerican. We believe there are meritorious defenses to the remaining claims or
requests for relief. However, we are unable at this time to determine the ultimate outcome of these lawsuits or their possible effect on our financial results.

Securities Class Action

Three federal securities class action lawsuits have been filed in the United States District Courts for the Southern District of New York and the
District of Maryland between September 2008 and November 2008. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A
Junior Subordinated Debentures (Debentures), of Constellation Energy between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008.
The securities class actions generally allege that Constellation Energy, a number of its present or former officers or directors, and the underwriters violated the securities laws by issuing a false
and misleading registration statement and prospectus in connection with Constellation Energy's June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation
Energy issued false or misleading statements or was aware of material undisclosed information which contradicted public statements including in connection with its announcements of financial results
for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek,
among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

A
lead plaintiff has not yet been appointed in the New York or Maryland securities class action lawsuits pursuant to the provisions of the Private Securities Litigation Reform Act and
Constellation Energy and other defendants have accordingly not been required to respond to the complaints or take other action to defend the litigation. The Southern District of New York has granted
the defendant's motion to transfer the two securities class actions filed there to the District of Maryland, to be coordinated with the securities class action filed there. We are unable at this time
to determine the ultimate outcome of the securities class actions or their possible effect on our, or BGE's financial results.

140

---



ERISA Actions

In the fall of 2008, multiple class action lawsuits were filed in the United States District Courts for the District of Maryland and the Southern
District of New York against Constellation Energy; Mayo A. Shattuck III, Constellation Energy's Chairman of the Board, President and Chief Executive Officer; and others in their roles as
fiduciaries of the Constellation Energy Employee Savings Plan. The actions, which have been consolidated into one action in Maryland (the Consolidated Action), allege that the defendants, in violation
of various sections of ERISA, breached their fiduciary duties to prudently and loyally manage Constellation Energy Savings Plan's assets by designating Constellation Energy common stock as an
investment, by failing to properly provide accurate information about the investment, by failing to properly monitor the investment and by failing to properly monitor other fiduciaries. The
Consolidated Action seeks to compel the defendants to reimburse the plaintiffs and the Constellation Energy Savings Plan for all losses resulting from the defendants' breaches of fiduciary duty, to
impose a constructive trust on any unjust enrichment, to award actual damages with pre- and post-judgment interest, to award appropriate equitable relief including injunction
and restitution and to award costs and expenses, including attorneys' fees. We are unable at this time to determine the ultimate outcome of the Consolidated Action or its possible effects on our, or
BGE's, financial results.

Mercury

Since September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for
Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to
BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued. Approximately 70
cases, involving claims related to approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.

In
rulings applicable to all but three of the cases, involving claims related to approximately 47 children, the Circuit Court for Baltimore City dismissed with prejudice all claims
against BGE and Constellation Energy. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We
believe that we have meritorious defenses and intend to defend the remaining actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or
BGE's, financial results.

Asbestos

Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon
the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation Energy, numerous other
parties are defendants in these cases.

Approximately
513 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages.
Cross-claims and third-party claims brought by other defendants may also be
filed against BGE and Constellation Energy in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment and a small minority have been
resolved for amounts that were not material to our financial results.

BGE
and Constellation Energy do not know the specific facts necessary to estimate their potential liability for these claims. The specific facts we do not know include:



Until
the relevant facts are determined, we are unable to estimate what our, or BGE's, liability might be. Although insurance and hold harmless agreements from contractors who employed
the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Storage of Spent Nuclear Fuel

The Nuclear Waste Policy Act of 1982 (NWPA) required the federal government through the DOE, to develop a repository for, and disposal of, spent
nuclear fuel and high-level radioactive waste. The NWPA and our contracts with the DOE required the DOE to begin taking possession of spent nuclear fuel generated by nuclear generating
units no later than January 31, 1998. The DOE has stated that it will not meet that obligation until 2020 at the earliest.

This
delay has required that we undertake additional actions related to on-site fuel storage at Calvert Cliffs and Nine Mile Point, including the installation of
on-site dry fuel storage capacity at Calvert Cliffs. In January 2004, we filed a complaint against the federal government in the United States Court of Federal Claims seeking to recover
damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998. The case is currently stayed, pending litigation in other
related cases.

In
connection with our purchases of Nine Mile Point and Ginna, all of the former owners' rights and obligations related to recovery of damages for DOE's failure to meet its contractual
obligations were assigned to us. However, we have an obligation to reimburse the former owner of Ginna for up to $10 million in recovered damages for such claims.

Nuclear Insurance

We maintain nuclear insurance coverage for Calvert Cliffs, Nine Mile Point, and Ginna in four program areas: liability, worker
radiation, property, and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.

141

---



In
November 2002, the President signed into law the Terrorism Risk Insurance Act (TRIA) of 2002, which was extended by the Terrorism Risk Insurance Extension Act of 2005 and the
Terrorism Risk Insurance Program Reauthorization Act of 2007. Under the TRIA, property and casualty insurance companies are required to offer insurance for losses resulting from certified acts of
terrorism. Certified acts of terrorism are determined by the Secretary of the Treasury, in concurrence with the Secretary of State and Attorney General, and primarily are based upon the occurrence of
significant acts of terrorism that intimidate the civilian population of the United States or attempt to influence policy or affect the conduct of the United States Government. Our nuclear liability,
nuclear property and accidental outage insurance programs, as discussed later in this section, provide coverage for certified acts of terrorism.

If
there were an accident or an extended outage at any unit of Calvert Cliffs, Nine Mile Point or Ginna, it could have a substantial adverse impact on our financial results.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of
public liability. This limit of liability consists of the maximum available commercial insurance of $300 million and mandatory participation in an industry-wide retrospective
premium assessment program. The retrospective premium assessment is $117.5 million per reactor, per incident, increasing the total amount of insurance for public liability to approximately
$12.5 billion. Under the retrospective assessment program, we can be assessed up to $587.5 million per incident at any commercial reactor in the country, payable at no more than
$87.5 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance. Both the maximum assessment per reactor and the maximum yearly assessment
are adjusted for inflation (Consumer Price Index) at least every five years and are subject to state premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to
pay claims.

Worker Radiation Claims Insurance

We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. The
policy provides a single industry aggregate limit of $200 million for occurrences of radiation injury claims against all those insured by this policy prior to January 1, 2003 and
$300 million for occurrences of radiation injury claims against all those insured by this policy on or after January 1, 2003.

The
sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority,
which continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for retrospective premiums and other premium assessments. RG&E, the seller of
Ginna, retains the
liabilities for existing and potential claims that occurred prior to June 10, 2004. If claims under these policies exceed the coverage limits, the provisions of the Price-Anderson Act would
apply.

Nuclear Property Insurance

Our policies provide $500 million in primary coverage at each nuclear plantCalvert Cliffs, Nine Mile Point, and Ginna. In
addition, we maintain $1.8 billion of excess coverage at Ginna and $2.3 billion in excess coverage under a blanket excess program offered by the industry mutual insurer at both Calvert
Cliffs and Nine Mile Point. Under the blanket excess policy, Calvert Cliffs and Nine Mile Point share $1.0 billion of the total $2.3 billion of excess property coverage. Therefore, in
the unlikely event of two full limit property damage losses at Calvert Cliffs and Nine Mile Point, we would recover $4.5 billion instead of $5.5 billion.

Losses
resulting from non-certified acts of terrorism are covered as a common occurrence, meaning that if non-certified terrorist acts occur against one or more
commercial nuclear power plants insured by our nuclear property insurance company within a 12-month period, they would be treated as one event and the owners of the plants where the acts
occurred would share one full limit of liability (currently $3.2 billion).

Accidental Nuclear Outage Insurance

Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit. Coverage begins after a
12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is
up to $490.0 million per unit at Calvert Cliffs and Ginna, $420.0 million for Unit 1 of Nine Mile Point, and $401.8 million for Unit 2 of Nine Mile Point. This amount can be
reduced by up to $98.0 million per unit at Calvert Cliffs and $84.0 million for Nine Mile Point Unit 1 and $80.4 million for Nine Mile Point Unit 2 if an outage of more than one
unit is caused by a single insured physical damage loss.

Both
the accidental nuclear outage insurance and the nuclear property insurance are currently purchased through the industry mutual insurance company. If accidents at plants insured by
the mutual insurance company cause a shortfall of funds, all policyholders could be assessed, with our share being up to $93.1 million. During 2008, the Board of Directors for the industry
mutual insurance company approved a change to our policy that, in the event of a credit-rating downgrade to below investment grade, would require us to post collateral in the form of a letter of
credit or cash equal to $93.1 million. Alternatively, we would be required to purchase insurance.

Non-Nuclear Property Insurance

Our conventional property insurance provides coverage of $1.0 billion per occurrence for Certified acts of terrorism as defined under TRIA,
Terrorism Risk Insurance Extension Act of 2005 and the Terrorism Risk Insurance Program Reauthorization Act of 2007. Our conventional property insurance program also provides coverage for
non-certified acts of terrorism up to an annual aggregate limit of $1.0 billion. If a terrorist act occurs at any of our facilities, it could have a significant adverse impact on
our financial results.

142

---



13Derivatives and Fair Value Measurements

Use of Derivative Instruments

Nature of Our Business and Associated Risks

Our business activities primarily include our merchant energy business and our regulated electric and gas business. Our merchant energy business
includes:



Our
regulated electric and gas businesses engage in electricity and gas transmission and distribution activities in Central Maryland at prices set by the Maryland PSC that are generally
designed to recover our costs, including purchased fuel and energy. Substantially all of our risk management activities involving derivatives occur outside our regulated businesses.

In
carrying out our merchant energy business activities, we purchase and sell power, fuel, and other energy-related commodities in competitive markets. These activities expose us to
significant risks, including market risk from price volatility for energy commodities and the credit risks of counterparties with which we enter into contracts. The sources of these risks include, but
are not limited to, the following:



Objectives and Strategies for Using Derivatives

Risk Management Activities

To
lower our exposure to the risk of unfavorable fluctuations in commodity prices, interest rates, and foreign currency rates, we routinely enter into derivative contracts,
such as fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges, for
hedging purposes. The objectives for entering into such hedging transactions primarily include:



Non-Risk
Management Activities

In
addition to the use of derivatives for risk management purposes, we also enter into derivative contracts for trading purposes primarily to achieve the following
objectives:



Accounting for Derivative Instruments

The accounting requirements for derivatives are governed by SFAS No. 133 which requires recognition of all qualifying
derivative instruments as either assets or liabilities on the balance sheet at fair value.

Accounting Designation

We must evaluate new and existing transactions and agreements to determine whether they are derivatives. SFAS No. 133 permits several possible
accounting treatments for derivatives that meet all of the applicable requirements of that standard. SFAS No. 133 requires mark-to-market as the default accounting
treatment for all
derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet
specific, restrictive criteria prescribed by SFAS No. 133, both at the time of designation and on an ongoing basis. The permissible accounting treatments under SFAS No. 133 include:



We
further discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements inNote 1.

143

---



NPNS

We elect NPNS accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities
expected to be used or sold over a reasonable period in the normal course of business. Once we elect NPNS classification for a given contract, we do not subsequently change the election and treat the
contract as a derivative using mark-to-market or hedge accounting.

Cash Flow Hedging

We generally elect cash flow hedge accounting for most of the derivatives that we use to hedge market price risk for our physical energy delivery
activities because hedge accounting more closely aligns the timing of earnings recognition and cash flows for the underlying business activities. Management monitors the potential impacts of commodity
price changes and, where appropriate, may enter into or close out derivative transactions designated as cash flow hedges.

Commodity
Cash Flow Hedges

Our
merchant energy business has designated fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and
energy for the years 2009 through 2016. Our merchant energy business had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive
loss" of $2,614.9 million at December 31, 2008 and $1,498.7 million at December 31, 2007.

We
expect to reclassify $1,565.8 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive loss" into earnings during the
next twelve months based on market prices at December 31, 2008. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2008, due to
future changes in market prices.

When
we determine that a forecasted transaction originally hedged has become probable of not occurring, we reclassify net unrealized gains or losses associated with those hedges from
"Accumulated other comprehensive loss" to earnings. We recognized in earnings the following pre-tax amounts on such contracts:



The
majority of the pre-tax loss reclassified in 2008 resulted from contracts that ceased to qualify for hedge accounting due to the announcement of the intention to sell a
majority of our international commodities operation. The majority of the pre-tax loss reclassified in 2007 resulted from the deconsolidation of CEP. The majority of the pre-tax
loss reclassified in 2006 resulted from the initial public offering of CEP and the sale of our gas-fired plants.

Interest
Rate Swaps Designated as Cash Flow Hedges

We
use interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances and to manage our exposure to fluctuations
in interest rates on variable rate debt. The effective portion of gains and losses on these interest rate cash flow hedges, net of associated deferred income tax effects, is recorded in "Accumulated
other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income. We reclassify gains and losses on the hedges from "Accumulated other comprehensive
income" into "Interest expense" in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur.

Accumulated
other comprehensive income includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling
$12.0 million at December 31, 2008 and $11.9 million at December 31, 2007. We expect to reclassify $0.7 million of pre-tax net gains on these
cash-flow hedges from "Accumulated other comprehensive income" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

Fair Value Hedging

We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate swaps and certain forward
contracts and price and basis swaps associated with natural gas fuel in storage. The objectives for electing fair value hedging in these situations are to manage our exposure to optimize the mix of
our fixed and floating-rate debt, and to hedge the value of our natural gas in storage.

Interest
Rate Swaps Designated as Fair Value Hedges

We
use interest rate swaps designated as fair value hedges to optimize the mix of fixed and floating-rate debt. We record any gains or losses on swaps that
qualify for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense." We record changes in fair value of the swaps in "Derivative
assets and liabilities" and changes in the fair value of the debt in "Long-term debt" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged
fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

During
2004, we entered into interest rate swaps qualifying as fair value hedges relating to $450 million of our fixed-rate debt maturing in 2012 and 2015, and
converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized gain of $55.9 million at December 31, 2008 and $11.8 million
at December 31, 2007 and was recorded as an increase in our "Derivative assets" and an increase in our "Long-term debt." We had no hedge ineffectiveness on these interest rate
swaps.

144

---



Hedge Ineffectiveness

For all categories of derivative instruments designated in hedging relationships, we recorded in earnings the following pre-tax gains
(losses) related to hedge ineffectiveness:

Year ended December 31,

2008

2007

2006(In millions)Cash-flow hedges

$
(121.0
)
$
(31.4
)
$
13.4Fair value hedges


20.6


24.4


27.7Total

$
(100.4
)
$
(7.0
)
$
41.1


The ineffectiveness amounts in the table above exclude $31.8 million and $7.3 million of pre-tax losses for the years
ended December 31, 2008 and 2007, respectively, representing the change in fair value of derivatives that no longer qualify for cash-flow hedge accounting. These amounts relate to
periods of insufficient price correlation between the hedge and the risk being hedged, but the derivatives qualify for and remain designated as hedges prospectively. In addition, we did not recognize
any gain/loss in 2008 related to the change in fair value for the portion of our fair value hedges excluded from ineffectiveness testing. However, we recognized a $3.8 million
pre-tax loss in 2007 and a $8.9 million pre-tax gain in 2006 related to the change in value for the portion of our fair value hedges excluded from ineffectiveness
testing.

Mark-to-Market

We generally apply mark-to-market accounting for risk management and trading activities for which changes in fair value more
closely reflect the economic performance of the underlying business activity. However, we also use mark-to-market accounting for derivatives related to the following physical
energy delivery activities:



Origination Gains

We
may record origination gains associated with commodity derivatives subject to mark-to-market accounting. Origination gains represent the initial
fair value of certain structured transactions that our wholesale marketing, risk management, and trading operation executes to meet the risk management needs of our customers. Historically,
transactions that result in origination gains have been unique and resulted in individually significant gains from a single transaction. We generally recognize origination gains when we are able to
obtain observable market data to validate that the initial fair value of the contract differs from the contract price. Origination gains recognized in the past three years include:



Termination or Restructuring of Commodity Derivative Contracts

We may terminate or restructure in-the-money contracts in exchange for upfront cash payments and a reduction or cancellation
of future performance obligations. The termination or restructuring of contracts allows us to lower our exposure to performance risk under these contracts. Such transactions resulted in the
realization of the following amounts of pre-tax earnings that otherwise would have been recognized over the life of these contracts:



Fair Value Measurements

SFAS No. 157,Fair Value Measurements, defines fair value, establishes a
framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an
orderly transaction between market participants at the measurement date (exit price).

SFAS
No. 157 also creates a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:



We
determine the fair value of our assets and liabilities using unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2)
whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available.

We
classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and
liability taken as a whole. We determine fair value for assets and liabilities classified as Level 1 by multiplying the market price by the quantity of the asset or liability. We primarily
determine fair value measurements classified as Level 2 or Level 3 using the income valuation approach, which involves discounting estimated cash flows.

We
present all derivatives recorded at fair value net with the associated fair value cash collateral. This presentation of the net position reflects our credit exposure for our
on-balance sheet

145

---



positions
but excludes the impact of any off-balance sheet positions and collateral. Examples of off-balance sheet positions and collateral include
in-the-money accrual contracts for which the right of offset exists in the event of default and letters of credit. We discuss our letters of credit in more detail in Note 8.

Recurring
Measurements

BGE's
assets and liabilities measured at fair value on a recurring basis are immaterial. Our merchant energy business segment's assets and liabilities measured at fair value
on a recurring basis consist of the following:

As of
December 31, 2008Assets

Liabilities(In millions)Cash equivalents

$
928.5

$
Debt and equity securities


1,069.5


Derivative instruments:Classified as derivative assets and liabilities:Current


1,465.0


(1,241.8
)Noncurrent


851.8


(1,115.0
)Total classified as derivative assets and liabilities


2,316.8


(2,356.8
)Classified as accounts receivable *


(1,244.6
)

Total derivative instruments


1,072.2


(2,356.8
)Total recurring fair value measurements

$
3,070.2

$
(2,356.8
)


Cash equivalents represent money market mutual funds which are included in "Cash and cash equivalents" and "Restricted cash" in the Consolidated
Balance Sheets. Debt and equity securities represent available-for-sale investments which are included in "Nuclear decommissioning trust funds" and "Other assets" in the
Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to all derivative positions, including futures, forwards, swaps, and options. We classify exchange-listed
contracts as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the remainder of our derivative contracts as "Derivative assets" or "Derivative liabilities" in our
Consolidated Balance Sheets.

The
table below disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required by SFAS No. 157. A primary focus
of SFAS No. 157 is the fair value hierarchy that provides information about how fair value measurements are determined. SFAS No. 157 requires each individual asset or liability that is
remeasured at fair value on a recurring basis to be presented in this table and classified, in its entirety, within the appropriate level in the fair value hierarchy. Therefore, the objective of this
table is to provide information about how each individual derivative contract is valued within the fair value hierarchy, regardless of whether a particular contract is eligible for netting against
other contracts or whether it has been collateralized.

The
table below sets forth by level within the fair value hierarchy the gross components of the Company's assets and liabilities that were measured at fair value on a recurring basis as
of December 31, 2008. These gross balances are intended solely to provide information on sources of inputs to fair value and proportions of fair value involving objective versus subjective
valuations and do not represent either our actual credit exposure or net economic exposure.

At December 31, 2008

Level 1

Level 2

Level 3

Netting and
Cash Collateral *

Total Net
Fair Value(In millions)Cash equivalents

$
928.5

$


$


$


$
928.5Debt and equity securities


305.4


764.1








1,069.5Derivative assets


1,565.2


45,499.3


4,793.6


(50,785.9
)

1,072.2Derivative liabilities


(1,728.7
)

(46,969.1
)

(4,756.6
)

51,097.6


(2,356.8
)Net derivative position


(163.5
)

(1,469.8
)

37.0


311.7


(1,284.6
)Total

$
1,070.4

$
(705.7
)
$
37.0

$
311.7

$
713.4


146

---



SFAS No. 157 requires us to prepare this table by separating each individual derivative contract that is in the money from each contract that is out of the
money. It also requires us to ignore master netting agreements and collateral for our derivatives. As a result, the gross "asset" and "liability" amounts under each of the three fair value levels far
exceed our actual economic exposure to commodity price risk and credit risk. Our actual economic exposure consists of the net derivative position combined with our nonderivative accrual contracts,
such as those for load-serving, and our physical assets, such as our power plants. Our actual credit risk exposure is reflected in the net derivative asset and derivative liability amounts
shown in the Total Net Fair Value column.

Increases
and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary
factors affecting the gross amounts are commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same,
because SFAS No. 157 requires separate presentation of contracts that are in the money from those that are out of the money. As a result, even fully hedged positions could exhibit increases in
the gross amounts if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could
actually increase the gross amounts in the table because of the required separation of contracts discussed above.

Cash
equivalents are comprised of exchange traded money market funds and money market mutual funds. These instruments are valued based upon unadjusted quoted prices in active markets and
are classified within Level 1.

Debt
and equity securities include trust assets securing certain executive benefits, other marketable securities, and our nuclear decommissioning trust funds. Trust assets securing
certain executive benefits consist of mutual funds, which are valued based upon unadjusted quoted prices in active markets and are classified within Level 1. Our other marketable securities
consist of publicly traded individual securities, which are valued based on unadjusted quoted prices in active markets and are classified within Level 1. Nuclear decommissioning trust funds
consist of a number of different types of securities, including the following:



Derivative
instruments include exchange-traded and bilateral contracts. Exchange-traded derivative contracts include futures and certain options. Bilateral derivative contracts include
swaps, forwards, certain options and complex structured transactions. We utilize models to measure the fair value of bilateral derivative contracts. Generally, we use similar models to value similar
instruments. Valuation models utilize various inputs, which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in
markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by
correlation or other means. However, the primary input to our valuation models is the forward commodity price. We have classified derivative contracts within the fair value hierarchy as follows:



In
order to determine fair value, we utilize various factors, including market data and assumptions that market participants would use in pricing assets or liabilities as well as
assumptions about the risks inherent in the inputs to the valuation technique. These factors include:



We
also record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of derivative assets and liabilities. The
effect of these uncertainties is not incorporated in market price information or other market-based estimates used to determine fair value of our mark-to-market energy
contracts. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we

147

---



record
valuation adjustments and determining the level of such adjustments and changes in those levels.

We
describe below the main types of valuation adjustments we record and the process for establishing each. Generally, increases in valuation adjustments reduce our earnings, and
decreases in valuation adjustments increase our earnings. However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the
underlying positions.



We
regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, consisting of various market price verification procedures, including the use of
pricing services and multiple broker quotes to support the market price of the various commodities in which we transact, as well as review and verification of models and changes to those models. These
activities are undertaken by individuals that are independent of those responsible for estimating fair value.

The
Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the
fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market
liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy or some combination thereof. While SFAS No. 157 requires
us to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using
inputs from a higher level in the hierarchy.

148

---



The
following table sets forth a reconciliation of changes in Level 3 fair value measurements:

2008(In millions)Balance at beginning of period

$
(147.1
)Realized and unrealized gains (losses):Recorded in income


471.2Recorded in other comprehensive income


(511.9
)Purchases, sales, issuances, and settlements


37.6Transfers into and out of Level 3


187.2Balance as of December 31, 2008

$
37.0Change in unrealized gains recorded in income relating to derivatives still held as of December 31, 2008

$
800.1


Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are
marked-to-market in our Consolidated Statements of Income (Loss) and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as
cash-flow hedges in our Consolidated Balance Sheets. We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various
hedging relationships inNote 1.

Realized
and unrealized gains (losses) include the realization of derivative contracts through maturity. This includes the fair value, as of the beginning of each quarterly reporting
period, of contracts that matured during each quarterly reporting period. Purchases, sales, issuances, and settlements represent cash paid or received for option premiums, and the acquisition or
termination of derivative contracts prior to maturity. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to
the model became unobservable. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the
criteria discussed on the previous page for classification in either Level 1 or Level 2. Because the depth and liquidity of the power markets varies substantially between regions and
time periods, the availability of observable inputs for substantially the full term and value of our bilateral derivative contracts changes frequently. As a result, we also expect derivatives balances
to transfer into and out of Level 3 frequently based on changes in the observable data available as of the end of the period.

Nonrecurring
Measurements

The
table below sets forth by level within the fair value hierarchy our financial assets and liabilities that were measured at fair value on a nonrecurring basis during
2008:

Fair Value at December 31, 2008

Level 1

Level 2

Level 3

Losses for the year ended December 31, 2008(In millions)Equity method investment

$
17.7

$
17.7

$


$


$
124.4


As described more fully inNote 2, during the third and fourth quarters of 2008 we recorded
other-than-temporary impairment charges of $54.7 million and $69.7 million, respectively, on our equity method investment in CEP. The fair value of CEP is a
Level 1 measurement because CEP is a publicly traded stock on the New York Stock Exchange and the fair value is a quoted price in an active market.

Fair Value of Financial Instruments

We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following
table:

2008At December 31,



2007Carrying
Amount

Fair
Value *

Carrying
Amount

Fair
Value(In millions)Investments and other assetsConstellation Energy

$
2,264.5

$
2,264.5

$
1,634.2

$
1,634.5Fixed-rate long-term debt:Constellation Energy (including BGE)


6,995.4


6,290.3


4,244.3


4,307.5BGE


2,265.1


1,990.2


2,215.1


2,178.6Variable-rate long-term debt:Constellation Energy (including BGE)


736.7


736.7


801.6


801.6BGE














We use the following methods and assumptions for estimating fair value disclosures for financial instruments:



149

---





14Stock-Based Compensation

Under our long-term incentive plans, we grant stock options, performance and service-based restricted stock, performance- and service-based units,
and equity to officers, key employees, and members of the Board of Directors. In May 2007, shareholders approved Constellation Energy's 2007 Long-Term Incentive Plan, under which we can
grant up to a total of 9,000,000 shares. Any shares covered by an outstanding award under any of our long-term incentive plans that are forfeited or cancelled, expire or are settled in
cash will become available for issuance under the 2007 Long-Term Incentive Plan. At December 31, 2008, there were 8,729,667 shares available for issuance under the 2007
Long-Term Incentive Plan. At December 31, 2008, we had stock options, restricted stock, performance unit and equity grants outstanding as discussed below. We may issue new shares,
reuse forfeited shares, or buy shares in the market in order to deliver shares to employees for our equity grants. BGE officers and key employees participate in our stock-based compensation plans. The
expense recognized by BGE in 2008, 2007, and 2006 was not material to BGE's financial results.

Non-Qualified Stock Options

Options are granted with an exercise price equal to the market value of the common stock at the date of grant, become vested over a
period up to three years (expense recognized in tranches), and expire ten years from the date of grant.

The
fair value of our stock-based awards was estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted- average assumptions:

2008

2007

2006Risk-free interest rate


2.57
%

4.69
%


%Expected life (in years)


4.0


4.0


Expected market price volatility factor


25.8
%

20.3
%


%Expected dividend yield


1.85
%

2.5
%


%


During 2006, no stock options were granted to employees in anticipation of the proposed merger with FPL Group, which was terminated in October 2006.

We
use the historical data related to stock option exercises in order to estimate the expected life of our stock options. We also use historical data (measured on a daily basis) for a
period equal to the duration of the expected life of option awards and implied volatilities for certain publicly traded options in Constellation Energy common stock in order to estimate the volatility
factor. We believe that the use of this data to estimate these factors provides a reasonable basis for our assumptions. The risk-free interest rate for the periods within the expected life
of the option is based on the U.S Treasury yield curve in effect and the expected dividend yield is based on our current estimate for dividend payout at the time of grant.

Summarized
information for our stock option grants is as follows:

2008

2007

2006Shares

Weighted-
Average
Exercise Price

Shares

Weighted-
Average
Exercise Price

Shares

Weighted-
Average
Exercise Price(Shares in thousands)Outstanding, beginning of year


6,145

$
55.90


6,051

$
47.23


7,172

$
45.24Granted with exercise prices at fair market value


1,434


93.79


1,759


76.22





Exercised


(375
)

47.02


(1,411
)

41.91


(1,050
)

33.77Forfeited/expired


(1,146
)

84.59


(254
)

67.85


(71
)

45.22Outstanding, end of year


6,058

$
59.99


6,145

$
55.90


6,051

$
47.23Exercisable, end of year


4,665

$
52.13


4,043

$
48.51


4,401

$
46.94Weighted-average fair value per share of options granted with exercise prices at fair market value




$
18.75




$
13.76




$



150

---



The following table summarizes additional information about stock options during 2008, 2007 and 2006:

2008

2007

2006(In millions)Stock Option Expense Recognized

$
11.0

$
15.1

$
6.7Stock Options Exercised:Cash Received for Exercise Price


20.2


43.4


35.5Intrinsic Value Realized by Employee


14.1


67.6


27.6Realized Tax Benefit


5.7


26.7


10.9Fair Value of Shares that Vested


98.3


82.7


82.6


As of December 31, 2008, we had $7.8 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards,
of which $6.2 million is expected to be recognized during 2009.

The
following table summarizes additional information about stock options outstanding at December 31, 2008 (stock options in thousands):

Outstanding

ExercisableWeighted-
Average
Remaining
Contractual
LifeRange of
Exercise
Prices

Stock
Options

Aggregate
Intrinsic
Value *

Stock
Options

Aggregate
Intrinsic
Value *(In millions)



(In millions)

(In years)$20.00  $  40.00


1,217

$



1,217

$



3.9$40.00  $  60.00


3,004





3,004





3.8$60.00  $  80.00


1,000





430





6.7$80.00  $100.00


837





14





8.66,058

$



4,665

$



Restricted Stock Awards

In addition to stock options, we issue common stock based on meeting certain service goals. This stock vests to participants at
various times ranging from one to five years if the service goals are met. In accordance with SFAS No. 123R, we account for our service-based awards as equity awards, whereby we recognize the
value of the market price of the underlying stock on the date of grant to compensation expense over the service period either ratably or in tranches (depending if the award has cliff or graded
vesting).

We
recorded compensation expense related to our restricted stock awards of $46.6 million in 2008, $35.8 million in 2007, and $24.5 million in 2006. The tax benefits
received associated with our restricted awards were $20.1 million in 2008, $17.6 million in 2007, and $10.9 million in 2006. Summarized share information for our restricted stock
awards is as follows:

2008

2007

2006(Shares in thousands)Outstanding, beginning of year


1,322


1,207


1,272Granted


365


710


511Released to participants


(536
)

(552
)

(502
)Canceled


(118
)

(43
)

(74
)Outstanding, end of year


1,033


1,322


1,207Weighted-average fair value of restricted stock granted (per share)

$
94.62

$
75.29

$
58.68Total fair value of shares for which restriction has lapsed (in millions)

$
49.7

$
44.5

$
27.6


As of December 31, 2008, we had $22.9 million of unrecognized compensation cost related to the unvested portion of outstanding restricted stock
awards expected to be recognized within a 39-month period. At December 31, 2008, we have recorded in "Common shareholders' equity" approximately $47.8 million and
approximately $42.3 million at December 31, 2007 for the unvested portion of service-based restricted stock granted from 2006 until 2008 to officers and other employees that is
contingently redeemable in cash upon a change in control.

Performance-Based Units

In accordance with SFAS No. 123R, we recognize compensation expense ratably for our performance-based awards, which are
classified as liability awards, for which the fair value of the award is remeasured at each reporting period. Each unit is equivalent to $1 in value and cliff vests at the end of a
three-year service and performance period. The level of payout is based on the achievement of certain performance goals at the end of the three-year period and will be settled
in cash. In 2008, we recorded a reduction of compensation expense of $3.2 million due to lower anticipated achievement. We reported compensation expense of $17.6 million in 2007, and
$24.0 million in 2006 for these awards. During the 12 months ended December 31, 2008, our 2005 performance-based unit award vested and we paid $24.2 million in cash to
settle the award. During the 12 months ended December 31, 2007, our 2004 performance-based unit award vested and we paid $19.7 million in cash to settle the award. As of
December 31, 2008 we had $3.7 million of unrecognized compensation cost related to the unvested portion of outstanding performance-based unit awards expected to be recognized within a
26-month period.

Equity-Based Grants

We recorded compensation expense of $0.9 million in 2008, $0.9 million in 2007, and $0.6 million in 2006 related
to equity-based grants to members of the Board of Directors.

151

---



15Merger and Acquisitions

Investment Agreement with EDF Group

On December 17, 2008, we entered into an Investment Agreement with EDF under which EDF will purchase from us a 49.99%
membership interest in our nuclear generation and operation business for $4.5 billion (subject to certain adjustments).

In
connection with this transaction, we issued 10,000 shares of 8% Series B Preferred Stock to EDF for an aggregate value of $1 billion. This $1 billion will be
subsequently credited against the $4.5 billion purchase price for EDF's membership interest at the time of closing. At that time, EDF will surrender all of the shares of Series B
Preferred Stock to us. We discuss the 8% Series B Preferred Stock in more detail inNote 9.

The
Investment Agreement also includes an asset put arrangement that provides us with additional liquidity of up to $2 billion. Pursuant to the put arrangement, we can exercise an
option through December 31, 2010 (or the termination of the Investment Agreement by EDF due to our breach of the Investment Agreement), to require EDF to acquire certain non-nuclear
generation assets. The execution of this put arrangement is subject to regulatory approval. We discuss this facility in more detail inNote 8.

In
connection with these transactions, EDF has reimbursed us $150 million for transaction costs, which is in addition to the purchase price, has agreed to make certain other
payments, and has also provided us with a $600 million interim backstop liquidity facility. We discuss this facility in more detail in Note 8.

Prior
to closing, we will transfer to our nuclear generation and operation business transactions with a negative mark-to-market value not to exceed
$700 million in the aggregate using a 10% discount rate. This transfer will occur in a manner that is to be determined and to be mutually acceptable to Constellation Energy and EDF.

Constellation
Energy and EDF are working to close the Investment Agreement in the third quarter of 2009. The Investment Agreement contains certain termination rights for both
Constellation Energy and EDF. If the Investment Agreement is terminated for a failure of the closing to occur after all regulatory approvals have been obtained, EDF will be required to pay
Constellation Energy a termination fee of $175 million.

In
addition, if the Investment Agreement is terminated, the Series B Preferred Stock will be redeemed at the later of the date of termination or December 31, 2009 for
$1 billion aggregate principal amount of 10% Senior Notes of Constellation Energy due June 30, 2010.

We
have agreed that the maximum aggregate liability of EDF for losses or damages in connection with the Investment Agreement would be limited to $1.5 billion. Our recourse for the
first $1 billion in losses or damages is limited to the Series B Preferred Stock or if the Series B Preferred Stock has been redeemed, the 10% Senior Notes or any cash received
upon redemption.

Termination of Merger Agreement with MidAmerican

On December 17, 2008 Constellation Energy and MidAmerican agreed to terminate the Agreement and Plan of Merger the parties
entered into on September 19, 2008.

In
connection with the termination and conversion of our Series A Preferred Stock, we made certain payments and issued certain securities to MidAmerican. Specifically, we:



We
discuss the merger termination fee in more detail inNote 2. We discuss the conversion of the Series A Preferred Stock
into cash, our common shares and 14% Senior Notes in more detail inNote 9.

Nufcor International Limited

On June 26, 2008, we acquired Nufcor International Limited (Nufcor). We include Nufcor as part of our Global Commodities
operations in our merchant energy business segment and have included its results of operations in our consolidated financial statements since the date of acquisition. Nufcor is a uranium market
participant that provides marketing services to uranium producers, utilities and an investment fund in the North American and European markets.

We
acquired 100% ownership of Nufcor for $102.8 million, including direct costs, of which $104.9 million was paid in cash at closing. Subsequent to closing, we received
$3.1 million back from the seller as a result of adjustments to Nufcor's net assets. As part of the purchase, we acquired $37.3 million in cash.

152

---



Our
final purchase price allocation related to Nufcor is as follows:

At June 26, 2008(In millions)Cash

$
37.3Fuel stocks


126.8Other current assets


8.5Total current assets


172.6Goodwill (1)(2)


6.3Other assets


30.4Total assets acquired


209.3Short-term borrowings


(28.0
)Unamortized energy contract liabilities


(15.8
)Other current liabilities


(29.7
)Total current liabilities


(73.5
)Unamortized energy contract liabilities


(33.0
)Total liabilities


(106.5
)Net assets acquired

$
102.8


The
pro-forma impact of the Nufcor acquisition would not have been material to our results of operations for the years ended December 31, 2008, 2007,
and 2006.

West Valley Power Plant

On June 1, 2008, we acquired the West Valley Power Plant, a 200 MW gas-fired peaking plant located in Utah for
approximately $88.6 million (including direct costs). We accounted for this transaction as an asset acquisition and have included this plant's results of operations in the Generation operations
of our merchant energy business segment since the date of acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and spare parts inventory.

Hillabee Energy Center

On February 14, 2008, we acquired the Hillabee Energy Center, a partially completed 774 MW gas-fired combined
cycle power generation facility located in Alabama for $156.9 million (including direct costs), which we accounted for as an asset acquisition. We allocated the purchase price primarily to the
equipment with lesser amounts allocated to land and contracts acquired. We plan to complete the construction of this facility and expect it to be ready for commercial operation in late 2009.

Cornerstone Energy

On July 1, 2007, we acquired Cornerstone Energy, Inc. (CEI). We include CEI, part of our retail competitive supply
operation, in our merchant energy business segment and have included its results of operations in our consolidated financial statements since the date of acquisition. CEI provides natural gas supply
and related services to commercial, industrial and institutional customers across the central United States. CEI is expected to add approximately 100 billion cubic feet of natural gas to our
annual volumes served.

We
acquired 100% ownership for $108.3 million, which we paid in cash. As part of the purchase, we acquired $7.3 million in cash.

The
total consideration for accounting purposes, consisting of cash and other noncash consideration, including the fair value of certain preexisting contracts with CEI, was equal to
$137.6 million.

Our
final purchase price allocation for the net assets acquired is as follows:

At July 1, 2007(In millions)Cash

$
7.3Other Current Assets


89.6Total Current Assets


96.9Goodwill (1)(2)


103.4Net Property, Plant and Equipment


0.5Other Assets


6.7Total Assets Acquired


207.5Current Liabilities


(66.3
)Deferred Credits and Other Liabilities


(3.6
)Total Liabilities


(69.9
)Net Assets Acquired

$
137.6


The pro-forma impact of the CEI acquisition would not have been material to our results of operations for the years ended
December 31, 2007 and 2006.

Acquisitions of Working Interests in Gas Producing Fields

In 2007, we acquired working interests of 41% and 55% in two gas and oil producing properties in Oklahoma for $208.9 million,
subject to closing adjustments. We purchased leases, producing wells, inventory, and related equipment.
We have included the results of operations from these properties in our merchant energy business segment since the date of acquisition.

Our
purchase price was allocated to the net assets acquired as follows:

At March 23, 2007(In millions)Property, Plant and EquipmentInventory

$
0.2Unproved property


28.8Proved property


179.9Net Assets Acquired

$
208.9


The pro-forma impact of the acquisition of these working interests would not have been material to our results of operations for the
years ended December 31, 2007 and 2006.

153

---



16Related Party Transactions

Constellation Energy

On March 31, 2008, our merchant energy business sold its working interest in 83 oil and natural gas producing wells in
Oklahoma to CEP, an equity method investment of Constellation Energy, for total proceeds of approximately $53 million. Our merchant energy business recognized a $14.3 million gain, net
of the minority interest gain of $0.7 million on the sale and exclusive of our 28.5% ownership interest in CEP. This gain is recorded in "Gains on Sales of Assets" in our Consolidated
Statements of Income (Loss).

BGEIncome Statement

BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. Bidding to
supply BGE's market-based standard offer service to electric customers will occur from time to time through a competitive bidding process approved by the Maryland PSC.

Our
merchant energy business will supply a portion of BGE's market-based standard offer service obligation to residential electric customers through May 31, 2011.

The
cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was as follows:

Year Ended December 31,

2008

2007

2006(In millions)Electricity purchased for resale expenses

$
802.0

$
1,139.6

$
1,062.0


In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other
corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated
entity.

The
following table presents the costs Constellation Energy charged to BGE in each period.

Year ended December 31,

2008

2007

2006(In millions)Charges to BGE

$
153.6

$
160.8

$
148.8


BGEBalance Sheet

BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating
subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues
commercial paper to manage consolidated cash requirements. Under this arrangement, BGE had invested $148.8 million at December 31, 2008 and $78.4 million at December 31,
2007.

BGE's
Consolidated Balance Sheets include intercompany amounts related to corporate functions performed at the Constellation Energy holding company, BGE's purchases to meet its standard
offer service obligation, BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them, and the participation of BGE's employees in the Constellation
Energy defined benefit plans.

We
believe our allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.

154

---



17Quarterly Financial Data (Unaudited)

Our
quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair statement. Our business is seasonal in nature with the peak sales
periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2008 Quarterly DataConstellation EnergyEarnings (Loss)
Per Share
from
Continuing
OperationsDilutedIncome (Loss)
from
Operations

Income (Loss)
from
Continuing
Operations

Income (Loss)
Applicable to
Common Stock



2008 Quarterly DataBGERevenues

Earnings (Loss)
Per Share of Common StockDiluted



Revenues

Income (Loss)
from Operations

Earnings (Loss)
Applicable to Common Stock(In millions, except per share amounts)





(In millions)Quarter Ended



















Quarter EndedMarch 31

$
4,812.2

$
254.3

$
145.7

$
145.7

$
0.81

$
0.81

March 31

$
1,105.8

$
137.7

$
73.0June 30


4,756.1


331.7


171.5


171.5


0.95


0.95

June 30


636.8


(131.1
)

(107.4
)September 30


5,323.6


(228.4
)

(225.7
)

(225.7
)

(1.27
)

(1.27
)
September 30


977.9


69.6


19.9December 31


4,926.4


(1,335.7
)

(1,405.9
)

(1,405.9
)

(7.75
)

(7.75
)
December 31


983.2


106.3


52.8Year Ended



















Year EndedDecember 31

$
19,818.3

$
(978.1
)
$
(1,314.4
)
$
(1,314.4
)
$
(7.34
)
$
(7.34
)
December 31

$
3,703.7

$
182.5

$
38.3


The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as
a result of issuing common shares during the year. Constellation Energy revenues for the quarter ended March 31, 2008 and June 30, 2008 have been reclassified to conform with the current
presentation.

First
quarter results include:



Second
quarter results include:



Third
quarter results include:



Fourth
quarter results include:



155

---





We
discuss these items inNote 2.

2007 Quarterly DataConstellation EnergyEarnings Per
Share from
Continuing
Operations
Diluted



2007 Quarterly DataBGERevenues

Income from
Operations

Income from
Continuing
Operations

Earnings
Applicable to
Common
Stock

Earnings Per
Share of
Common
StockDiluted



Revenues

Income from
Operations

Earnings
Applicable to
Common
Stock(In millions, except per share amounts)





(In millions)Quarter Ended



















Quarter EndedMarch 31

$
5,111.1

$
302.4

$
197.3

$
195.7

$
1.08

$
1.07

March 31

$
922.1

$
136.0

$
66.0June 30


4,876.3


154.4


116.3


116.3


0.64


0.64

June 30


707.1


50.5


13.6September 30


5,856.4


425.1


250.7


251.4


1.37


1.38

September 30


896.9


66.5


24.4December 31


5,349.4


452.5


258.1


258.1


1.42


1.42

December 31


892.4


81.3


22.6Year Ended



















Year EndedDecember 31

$
21,193.2

$
1,334.4

$
822.4

$
821.5

$
4.51

$
4.50

December 31

$
3,418.5

$
334.3

$
126.6


The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as
a result of issuing common shares during the year. Constellation Energy revenues for the quarter ended March 31, 2007 and June 30, 2007 have been reclassified to conform with the current
presentation.

First
quarter results include:



Second
quarter results include:



Third
quarter results include:



Fourth
quarter results include:



We
discuss these items inNote 2.

156

---





---

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

---

Items 9A and 9A(T). Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The principal executive officers and principal financial officers of both Constellation Energy and BGE have evaluated the effectiveness of the
disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"))
as of December 31, 2008 (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's and BGE's disclosure controls and
procedures are effective.

Internal Control Over Financial Reporting

Each of Constellation Energy and BGE maintains a system of internal control over financial reporting as defined in Exchange Act
Rule 13a-15(f). The Management's Reports on Internal Control Over Financial Reporting of each of Constellation Energy and BGE are included inItem 8.
Financial Statements and Supplementary Dataincluded in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, its
Management's Report on Internal Control Over Financial Reporting is not deemed to be filed for purposes of Section 18 of the Exchange Act as permitted by the rules and regulations of the
Securities and Exchange Commission.

Changes in Internal Control

During the quarter ended December 31, 2008, there has been no change in either Constellation Energy's or BGE's internal
control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely
to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

---

Item 9B. Other Information

None.

---

PART III

BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced
disclosure format. Accordingly, all items in this section related to BGE are not presented.

Item 10. Directors and Executive Officers of the Registrant

The information required by this item with respect to directors will be set forth underElection of
Directorsin the Proxy Statement and incorporated herein by reference.

The
information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K, is set forth following Item 4 of Part I of this Form 10-K underExecutive Officers of the
Registrant.

Item 11. Executive Compensation

The information required by this item will be set forth underExecutive and Director
CompensationandReport of Compensation Committeein the Proxy Statement and incorporated herein by reference.

---

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The additional information required by this item will be set forth underStock
Ownershipin the Proxy Statement and incorporated herein by reference.

157

---



Equity Compensation Plan Information

The following table reflects our equity compensation plan information as of December 31, 2008:

(a)



(c)Number of securities
to be issued upon
exercise of
outstanding options,
warrants, and rights

(b)

Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in item (a))Plan Category

Weighted-average
exercise price of
outstanding options,
warrants, and rights(In thousands)



(In thousands)Equity compensation plans approved by security holders


5,220

$
62.79


8,730Equity compensation plans not approved by security holders


838

$
42.56


Total


6,058

$
59.99


8,730


The plans that do not require shareholder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as
Exhibit No. 10(m)) and the Constellation Energy Group, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 10(n)). A brief description of the material
features of each of these plans is set forth below.

2002 Senior Management Long-Term Incentive Plan

The 2002 Senior Management Long-Term Incentive Plan became effective May 24, 2002 and authorized the issuance of up to 4,000,000
shares of Constellation Energy common stock in connection with the grant of equity awards. No further awards will be made under this plan. Any shares covered by an outstanding award that is forfeited
or cancelled, expires or is settled in cash will become available for issuance under the shareholder-approved 2007 Long-Term Incentive Plan. Shares delivered pursuant to awards under this
plan may be authorized and unissued shares or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit, and performance unit award
payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by
Constellation Energy's Chief Executive Officer.

Management Long-Term Incentive Plan

The Management Long-Term Incentive Plan became effective February 1, 1998 and authorized the issuance of up to 3,000,000 shares of
Constellation Energy common stock in connection with the grant of equity awards. No further awards will be made under this plan. Any shares covered by an outstanding award that is forfeited or
cancelled, expires or is settled in cash will become available for issuance under the shareholder-approved 2007 Long-Term Incentive Plan. Shares delivered pursuant to awards under the plan
may be authorized and unissued shares or shares purchased on the open market in accordance with applicable securities laws. Restricted stock, restricted stock units, and performance unit award payouts
will be accelerated and stock options and stock appreciation rights will become fully exercisable in the event of a change in control, as defined by the plan. The plan is administered by Constellation
Energy's Chief Executive Officer.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The additional information required by this item will be set forth underRelated Persons
TransactionsandDetermination of Independencein the Proxy Statement and incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

The information required by this item will be set forth underRatification of
PricewaterhouseCoopers LLP as Independent Registered Public Accounting Firm for 2009in the Proxy Statement and incorporated herein by reference.

158

---





PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as a part of this Report:1.

Financial Statements:Reports of Independent Registered Public Accounting Firm dated February 27, 2009 of PricewaterhouseCoopers LLPConsolidated Statements of Income (Loss)Constellation Energy Group for three years ended December 31, 2008Consolidated Balance SheetsConstellation Energy Group at December 31, 2008 and December 31, 2007Consolidated Statements of Cash FlowsConstellation Energy Group for three years ended December 31, 2008Consolidated Statements of Common Shareholders' Equity and Comprehensive IncomeConstellation Energy Group for three years ended
December 31, 2008Consolidated Statements of IncomeBaltimore Gas and Electric Company for three years ended December 31, 2008Consolidated Balance SheetsBaltimore Gas and Electric Company at December 31, 2008 and December 31, 2007Consolidated Statements of Cash FlowsBaltimore Gas and Electric Company for three years ended December 31, 2008Notes to Consolidated Financial Statements2.

Financial Statement Schedules:Schedule IIValuation and Qualifying AccountsSchedules other than Schedule II are omitted as not applicable or not required.3.

Exhibits Required by Item 601 of Regulation S-K.




Exhibit
Number*2



Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement
on Form S-4 dated March 3, 1999, File No. 33-64799.)*2
(a)


Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)*2
(b)


Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)*2
(c)


Termination Agreement, dated December 17, 2008, by and among Constellation Energy Group, Inc., Constellation Generation II, LLC, Constellation Power Source Generation, Inc., MidAmerican Energy
Holdings Company, MEHC Merger Sub Inc., MEHC Investment, Inc. and Electricite de France International S.A. (Designated as Exhibit 2.1 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*2
(d)


Master Put Option and Membership Interest Purchase Agreement, dated as of December 17, 2008, by and among Constellation Energy Group, Inc., EDF Development, Inc. and Electricite de France International,
 S.A. (Designated as Exhibit No. 21 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*3
(a)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of December 17, 2008. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated December 17, 2008, File
No. 1-12869.)*3
(b)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of September 19, 2008. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated September 19, 2008, File
No. 1-12869.)3
(c)


Certificate of Correction to Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 25, 2008.


159

---



*3
(d)


Articles of Amendment to the Charter of Constellation Energy Group, Inc. as of July 21, 2008. (Designated as Exhibit No. 3(a) to the Quarterly Report on Form 10-Q dated June 30, 2008, File
Nos. 1-12869 and 1-1910.)*3
(e)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of April 10, 2007. (Designated as Exhibit 3(a) to the Current Report on Form 8-K dated April 10, 2007, File
No. 1-12869.)*3
(f)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001. (Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31,
2001, File Nos. 1-12869 and 1-1910.)*3
(g)


Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended
December 31, 1999, File Nos. 1-12869 and 1-1910.)*3
(h)


Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30,
1999, File Nos. 1-12869 and 1-1910.)*3
(i)


Articles of Amendment and Restatement of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Appendix B to Post-Effective Amendment No. 1 to the Registration Statement on
Form S-4 filed March 3, 1999, File No. 33-64799.)*3
(j)


Bylaws of Constellation Energy Group, Inc., as amended to July 18, 2008. (Designated as Exhibit No. 3 to the Current Report on Form 8-K dated July 18, 2008, File No. 1-12869.)*3
(k)


Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, File No. 1-1910.)*3
(l)


Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)*4
(a)


Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated
March 29, 1999, File No. 333-75217.)*4
(b)


First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on
Form S-3 dated January 24, 2003, File No. 333-102723.)*4
(c)


Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the
quarter ended June 30, 2008, File Nos. 1-12869 and 1-1910.)*4
(d)


Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3,
File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26,
 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)*4
(e)


Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement
on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(f)


Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) to the Registration
Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(g)


Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(h)


Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(i)


Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)


160

---



*4
(j)


Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3
filed July 24, 2006, File No. 333-135991.)*4
(k)


First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated as of June 27, 2008. (Designated as Exhibit No. 4(a) to the Current Report
on Form 8-K dated June 30, 2008, File No. 1-12869.)*4
(l)


Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3
filed July 24, 2006, File No. 333-135991.)*4
(m)


First Supplemental Indenture between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee, dated as of October 13, 2006. (Designated as Exhibit 4(a) to the Quarterly Report on
Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)*4
(n)


Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on
Form 8-K dated July 5, 2007, File No. 1-1910.)*4
(o)


Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit 4.2 to the
Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)*4
(p)


Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated June 30, 2008, File No. 1-12869.)+*10
(a)


Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September30, 2008,
File Nos. 1-12869 and 1-1910.)+10
(b)


Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.10
(c)


Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.+10
(d)


Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated.+10
(e)


Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.+10
(f)


Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.+*10
(g)


Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File
Nos. 1-12869 and 1-1910.)+10
(h)


Second amended and restated change in control severance agreement between Constellation Energy Group, Inc. and Mayo A. Shattuck III.+10
(i)


Second amended and restated change in control severance agreement between Constellation Energy Group, Inc. and John R. Collins.+*10
(j)


Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004,
File Nos. 1-12869 and 1-1910.)+*10
(k)


Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006,
File Nos. 1-12869 and 1-1910.)+*10
(l)


Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated. (Designated as Exhibit 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2006, File
Nos. 1-12869 and 1-1910.)+*10
(m)


Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended
September 30, 2006, File Nos. 1-12869 and 1-1910.)


161

---



+*10
(n)


Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006,
 File Nos. 1-12869 and 1-1910.)+*10
(o)


Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File
Nos. 1-12869 and 1-1910.)*10
(p)


Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 2004, File Nos. 1-12869 and 1-1910.)*10
(q)


Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for
the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)*10
(r)


Rate Stabilization Property Servicing Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report
on Form 8-K dated July 5, 2007, File No. 1-1910.)*10
(s)


Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K
dated July 5, 2007, File No. 1-1910.)*10
(t)


Investor Rights Agreement, dated as of September 19, 2008, by and between Constellation Energy Group, Inc. and MidAmerican Energy Holdings Company. (Designated as Exhibit No. 10.3 to the Current Report on
Form 8-K dated September 19, 2008, File No. 1-12869.)*10
(u)


Letter Agreement, dated December 17, 2008, by and among Constellation Energy Group, Inc., MidAmerican Energy Holdings Company, MEHC Merger Sub Inc. and MEHC Investment, Inc. (Designated as Exhibit
No. 10.1 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(v)


Form of CENG Operating Agreement (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(w)


Stock Purchase Agreement, dated as of December 17, 2008, by and among Constellation Energy Group, Inc., EDF Development, Inc. and Electricite de France International, S.A. (Designated as Exhibit
No. 10.2 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(x)


Investor Rights Agreement, dated as of December 17, 2008, by and between Constellation Energy Group, Inc. and EDF Development, Inc. (Designated as Exhibit No. 10.3 to the Current Report on
Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(y)


Payment Guaranty, dated as of December 17, 2008, by and between Constellation Energy Group, Inc. and Electricite de France, S.A. (Designated as Exhibit No. 10.4 to the Current Report on Form 8-K
dated December 17, 2008, File No. 1-12869.)*10
(z)


Amended and Restated Investor Agreement, dated December 17, 2008, by and between Constellation Energy Group, Inc. and Electricite de France International, SA (Designated as Exhibit 10.7 to the Current
Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(aa)


Amended and Restated Credit Agreement, dated as of December 17, 2008, among Constellation Energy Group, Inc., the Lenders named therein and the Royal Bank of Scotland PLC, as Administrative Agent.
(Designated as Exhibit No. 10.5 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(bb)


Second Amended and Restated Credit Agreement, dated as of December 17, 2008, among Constellation Energy Group, Inc., the Lenders named therein, Wachovia Bank, National Association, as Administrative Agent, LC
Bank, Swingline Lender and Collateral Agent. (Designated as Exhibit No. 10.6 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)12
(a)


Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.12
(b)


Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend
Requirements.21



Subsidiaries of the Registrant.


162

---



23



Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.31
(a)


Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
(b)


Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
(c)


Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
(d)


Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32
(a)


Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.32
(b)


Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.32
(c)


Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32
(d)


Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.


163

---



Table of Contents

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIESANDBALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES

SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

Column A

Column B

Column C

Column D

Column EAdditionsDescription

Balance at
beginning
of period

Charged
to costs
and expenses

Charged to
Other Accounts
Describe

(Deductions)
Describe

Balance at
end of
period(In millions)Reserves deducted in the Balance Sheet from the assets to which they apply:Constellation EnergyAccumulated Provision for Uncollectibles2008

$
44.9

$
127.1

$
102.3
(A)
$
(33.7
)(B)
$
240.62007


48.9


31.3





(35.3
)(B)

44.92006


47.4


29.7





(28.2
)(B)

48.9Valuation AllowanceNet unrealized (gain) loss on available for sale securities2008


(17.3
)

7.0


0.3
(C)

12.1
(D)

2.12007


(18.5
)




1.2
(C)




(17.3
)2006


0.6





(19.1
)(C)




(18.5
)Net unrealized (gain) loss on nuclear decommissioning trust funds2008


(256.7
)




207.1
(C)




(49.6
)2007


(206.1
)




(50.6
)(C)




(256.7
)2006


(110.3
)




(95.8
)(C)




(206.1
)BGEAccumulated Provision for Uncollectibles2008


21.1


34.5





(21.4
)(B)

34.22007


16.1


21.0





(16.0
)(B)

21.12006


13.0


18.1





(15.0
)(B)

16.1


164

---





Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.

CONSTELLATION ENERGY GROUP, INC. (REGISTRANT)Date: February 27, 2009

By

/s/

MAYO A. SHATTUCKIIIMayo A. Shattuck IIIChairman of the Board, President and Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy
Group, Inc., the Registrant, and in the capacities and on the dates indicated.

Signature

Title

DatePrincipal executive officer and director:By

/s/

M. A. Shattuck III

Chairman of the Board, President, Chief Executive Officer, and Director

February 27, 2009M. A. Shattuck IIIPrincipal financial officer:By

/s/

J. W. Thayer

Senior Vice President and Chief Financial Officer

February 27, 2009J. W. ThayerPrincipal accounting officer:By

/s/

R. K. Feuerman

Vice President, Chief Accounting Officer, and Treasurer

February 27, 2009R. K. FeuermanDirectors:/s/

Y. C. de Balmann

Director

February 27, 2009Y. C. de Balmann/s/

D. L. Becker

Director

February 27, 2009D. L. Becker/s/

A. C Berzin

Director

February 27, 2009A. C. Berzin/s/

J. T. Brady

Director

February 27, 2009J. T. Brady/s/

J. R. Curtiss

Director

February 27, 2009J. R. Curtiss


165

---



Table of Contents

Signature

Title

Date/s/

F. A. Hrabowski, III

Director

February 27, 2009F. A. Hrabowski, III/s/

N. Lampton

Director

February 27, 2009N. Lampton/s/

R. J. Lawless

Director

February 27, 2009R. J. Lawless/s/

L. M. Martin

Director

February 27, 2009L. M. Martin/s/

J. L. Skolds

Director

February 27, 2009J. L. Skolds/s/

M. D. Sullivan

Director

February 27, 2009M. D. Sullivan


166

---



Table of Contents

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this
Report to be signed on its behalf by the undersigned, thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT)February 27, 2009

By

/s/

KENNETH W. DEFONTES, JR.Kenneth W. DeFontes, Jr.President and Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company,
the Registrant, and in the capacities and on the dates indicated.

Signature

Title

DatePrincipal executive officer and director:By

/s/

K. W. DeFontes, Jr.

President, Chief Executive Officer, and Director

February 27, 2009K. W. DeFontes, Jr.Principal financial and accounting officer:By

/s/

K. W. Hadlock

Senior Vice President and Chief Financial Officer

February 27, 2009K. W. HadlockDirectors:/s/

T. F. Brady

Chairman of the Board of Directors

February 27, 2009T. F. Brady/s/

M. A. Shattuck III

Director

February 27, 2009M. A. Shattuck III/s/

J. Haskins Jr.

Director

February 27, 2009J. Haskins Jr./s/

C. Hayden

Director

February 27, 2009C. Hayden/s/

M. D. Sullivan

Director

February 27, 2009M. D. Sullivan


167

---



Table of Contents

EXHIBIT INDEX

Exhibit
Number*2



Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement
on Form S-4 dated March 3, 1999, File No. 33-64799.)*2
(a)


Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)*2
(b)


Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)*2
(c)


Termination Agreement, dated December 17, 2008, by and among Constellation Energy Group, Inc., Constellation Generation II, LLC, Constellation Power Source Generation, Inc., MidAmerican Energy Holdings
Company, MEHC Merger Sub Inc., MEHC Investment, Inc. and Electricite de France International S.A. (Designated as Exhibit 2.1 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*2
(d)


Master Put Option and Membership Interest Purchase Agreement, dated as of December 17, 2008, by and among Constellation Energy Group, Inc., EDF Development, Inc. and Electricite de France International,
 S.A. (Designated as Exhibit No. 21 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*3
(a)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of December 17, 2008. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated December 17, 2008, File
No. 1-12869.)*3
(b)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of September 19, 2008. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated September 19, 2008, File
No. 1-12869.)3
(c)


Certificate of Correction to Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 25, 2008.*3
(d)


Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated April 30,
1999, File No. 1-1910.)*3
(e)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of April 10, 2007. (Designated as Exhibit 3(a) to the Current Report on Form 8-K dated April 10, 2007, File
No. 1-12869.)*3
(f)


Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001. (Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31,
2001, File Nos. 1-12869 and 1-1910.)*3
(g)


Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended
December 31, 1999, File Nos. 1-12869 and 1-1910.)*3
(h)


Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30,
1999, File Nos. 1-12869 and 1-1910.)*3
(i)


Articles of Amendment and Restatement of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Appendix B to Post-Effective Amendment No. 1 to the Registration Statement on
Form S-4 filed March 3, 1999, File No. 33-64799.)*3
(j)


Bylaws of Constellation Energy Group, Inc., as amended to July 18, 2008. (Designated as Exhibit No. 3 to the Current Report on Form 8-K dated July 18, 2008, File No. 1-12869.)*3
(k)


Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, File No. 1-1910.)*3
(l)


Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)


168

---



Table of Contents

*4
(a)


Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated
March 29, 1999, File No. 333-75217.)*4
(b)


First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on
Form S-3 dated January 24, 2003, File No. 333-102723.)*4
(c)


Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the
quarter ended June 30, 2008, File Nos. 1-12869 and 1-1910.)*4
(d)


Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3,
File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26,
 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)*4
(e)


Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement
on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(f)


Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) to the Registration
Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(g)


Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(h)


Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(i)


Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)*4
(j)


Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3
filed July 24, 2006, File No. 333-135991.)*4
(k)


First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated as of June 27, 2008. (Designated as Exhibit No. 4(a) to the Current Report
on Form 8-K dated June 30, 2008, File No. 1-12869.)*4
(l)


Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3
filed July 24, 2006, File No. 333-135991.)*4
(m)


First Supplemental Indenture between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee, dated as of October 13, 2006. (Designated as Exhibit 4(a) to the Quarterly Report on
Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)*4
(n)


Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on
Form 8-K dated July 5, 2007, File No. 1-1910.)*4
(o)


Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit 4.2 to the
Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)*4
(p)


Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated June 30, 2008, File No. 1-12869.)+*10
(a)


Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30,
2008, File Nos. 1-12869 and 1-1910.)+10
(b)


Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.


169

---



Table of Contents

10
(c)


Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.+10
(d)


Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated.+10
(e)


Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.+10
(f)


Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.+*10
(g)


Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File
Nos. 1-12869 and 1-1910.)+10
(h)


Second amended and restated change in control severance agreement between Constellation Energy Group, Inc. and Mayo A. Shattuck III.+10
(i)


Second amended and restated change in control severance agreement between Constellation Energy Group, Inc. and John R. Collins+*10
(j)


Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004,
File Nos. 1-12869 and 1-1910.)+*10
(k)


Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006,
File Nos. 1-12869 and 1-1910.)+*10
(l)


Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated. (Designated as Exhibit 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2006, File
Nos. 1-12869 and 1-1910.)+*10
(m)


Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended
September 30, 2006, File Nos. 1-12869 and 1-1910.)+*10
(n)


Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006,
 File Nos. 1-12869 and 1-1910.)+*10
(o)


Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File
Nos. 1-12869 and 1-1910.)*10
(p)


Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 2004, File Nos. 1-12869 and 1-1910.)*10
(q)


Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for
the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)*10
(r)


Rate Stabilization Property Servicing Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report
on Form 8-K dated July 5, 2007, File No. 1-1910.)*10
(s)


Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K
dated July 5, 2007, File No. 1-1910.)*10
(t)


Investor Rights Agreement, dated as of September 19, 2008, by and between Constellation Energy Group, Inc. and MidAmerican Energy Holdings Company. (Designated as Exhibit No. 10.3 to the Current Report on
Form 8-K dated September 19, 2008, File No. 1-12869.)*10
(u)


Letter Agreement, dated December 17, 2008, by and among Constellation Energy Group, Inc., MidAmerican Energy Holdings Company, MEHC Merger Sub Inc. and MEHC Investment, Inc. (Designated as Exhibit
No. 10.1 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(v)


Form of CENG Operating Agreement (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)


170

---



Table of Contents

*10
(w)


Stock Purchase Agreement, dated as of December 17, 2008, by and among Constellation Energy Group, Inc., EDF Development, Inc. and Electricite de France International, S.A. (Designated as Exhibit
No. 10.2 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(x)


Investor Rights Agreement, dated as of December 17, 2008, by and between Constellation Energy Group, Inc. and EDF Development, Inc. (Designated as Exhibit No. 10.3 to the Current Report on
Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(y)


Payment Guaranty, dated as of December 17, 2008, by and between Constellation Energy Group, Inc. and Electricite de France, S.A. (Designated as Exhibit No. 10.4 to the Current Report on Form 8-K
dated December 17, 2008, File No. 1-12869.)*10
(z)


Amended and Restated Investor Agreement, dated December 17, 2008, by and between Constellation Energy Group, Inc. and Electricite de France International, SA (Designated as Exhibit 10.7 to the Current
Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(aa)


Amended and Restated Credit Agreement, dated as of December 17, 2008, among Constellation Energy Group, Inc., the Lenders named therein and the Royal Bank of Scotland PLC, as Administrative Agent.
(Designated as Exhibit No. 10.5 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)*10
(bb)


Second Amended and Restated Credit Agreement, dated as of December 17, 2008, among Constellation Energy Group, Inc., the Lenders named therein, Wachovia Bank, National Association, as Administrative Agent, LC
Bank, Swingline Lender and Collateral Agent. (Designated as Exhibit No. 10.6 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869.)12
(a)


Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.12
(b)


Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend
Requirements.21



Subsidiaries of the Registrant.23



Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.31
(a)


Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
(b)


Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
(c)


Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
(d)


Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32
(a)


Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.32
(b)


Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.32
(c)


Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32
(d)


Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.


171

---