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

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries and joint ventures organized around three business segments: a generation business (Generation), a customer supply business (NewEnergy), and Baltimore Gas and Electric Company (BGE). We describe our operating segments in Note 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 in Item 1. Business section and the risk factors affecting our business in Item 1A. Risk Factors section.

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 2009, 2008, and 2007. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income (Loss).

As a result of significant market events in 2008, we previously disclosed plans to refocus and, in some cases, exit parts of our NewEnergy business. We also sought to increase available liquidity and reduce our business risk. In addition, in November 2009, we completed a transaction to sell to EDF Group and affiliates (EDF) a 49.99% interest in our nuclear generation and operation business. This transaction brought us stability as a stand-alone company as well as improved our liquidity. We discuss the transaction with EDF and our divestitures in Note 2 to Consolidated Financial Statements and our available liquidity and risk management activities later in this Item 7.

We are pursuing a strategy of owning and operating generation facilities through our Generation business, providing energy and energy-related products and services through our NewEnergy business, and delivering electricity and gas to customers of BGE, our regulated utility located in central Maryland. Our Generation and NewEnergy businesses are focusing on short-term and long-term purchases and sales of energy, capacity, and related products to various customers, including distribution utilities, municipalities, cooperatives, and residential, 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 coal, natural gas, oil, and renewable sources. In addition to owning generating facilities, we contract for power from merchant providers, typically through power purchase agreements. We use both our owned generation and our contracted generation to support our wholesale and retail NewEnergy business.

Our NewEnergy business actively manages both physical and contractual assets in order to derive incremental value. The combination of our Generation and NewEnergy businesses allows us to manage our NewEnergy business in a collateral-efficient manner. Through our retail sales channels, we are able to manage our generation with lower requirements to post collateral. Additionally, when we use owned or contracted generation, we reduce our collateral posting requirements.

We have load obligations greater than our generation assets. Going forward, we intend to buy generation assets and enter into longer-tenor agreements with merchant generators in regions where we currently serve load but do not have a significant generation presence. We believe that by better matching generating assets with our load obligations, we will be able to further reduce our dependence on exchange-traded products, thereby lowering our collateral requirements. We believe that the proceeds received from the transaction with EDF, along with overall market conditions, provide the resources and potential opportunities to add to our generation assets at attractive prices over the next two to three years.

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

While we pursue the above strategy with our Generation and NewEnergy businesses, we are continuing a disciplined approach to the management of our collateral requirements and liquidity, including:

We are also in the forefront of the proposed development of new nuclear generation in the United States through our UniStar Nuclear Energy (UNE) joint venture with EDF. EDF brings operational experience, global scale, and procurement leverage to the development of new nuclear plants in the United States.

Various factors affect our financial results. We discuss some of these factors in more detail in Item 1. Business—Competition section. We also discuss these various factors in the Forward Looking Statements and Item 1A. Risk Factors sections.

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. In 2009, markets in which we operate were affected by declining prices for power, gas, and capacity.

During 2009, we improved our liquidity and reduced our business risk in response to these market events. We discuss our liquidity and collateral requirements in the Financial Condition section. 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 the Risk Management section. Competition impacts our business.

We discuss competition in more detail in Item 1. Business—Competition section. The impacts of electric deregulation on BGE in Maryland are discussed in Item 1. Business—Baltimore Gas and Electric Company—Electric Business—Electric Competition section.

In addition to electric restructuring, which we discuss in Item 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), and certain taxes and surcharges. The rates for BGE's regulated gas business continue to consist of a delivery charge (base rates as well as certain taxes and surcharges) and a commodity charge.

In October 2009, the Maryland PSC issued an order approving our transaction with EDF subject to the following conditions, with which both Constellation Energy and EDF are complying:

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:

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 did not recommend returning the former utility generation assets to full cost of service regulation, but rather recommended incremental, forward looking re-regulation when appropriate to ensure a reliable supply of electricity or to obtain economic benefits for customers. In 2009, the Maryland PSC continued to examine how to procure electric supply for Maryland residents, from modifications to the existing auction process to requiring that new generation be built by the utilities or by third parties. 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 the Risk Management section.

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, subject to limitations in the Maryland PSC's October 2009 order approving our transaction with EDF. 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).

The Maryland PSC has allowed us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers since 2008 and for the majority of our large commercial and industrial customers since February 2009 to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings. We have a similar revenue decoupling mechanism in our gas business.

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 in Item 1. Business—Baltimore Gas and Electric Company—Electric Load Management.

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

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 the Regulated Gas Business—Gas Cost Adjustments section and in Note 6 to Consolidated Financial Statements.

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 a number of orders covering various new transmission investment projects since 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 Generation and NewEnergy businesses participate 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.

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 NewEnergy business. FERC has stated that it would issue a substantive order on the ALJ's decision no later than the end of May 2010. Nonetheless, the amounts collected under the SECA rates are subject to refund and the ultimate outcome of the proceeding establishing SECA rates is uncertain. Depending on the ultimate outcome, the proceeding may have a material effect on our financial results.

In general, capacity market design revisions are routinely proposed and considered on an ongoing basis. Such changes are subject to FERC's review and approval. Currently, we cannot predict the outcome of these proceedings or the possible effect on our, or BGE's, financial results.

Through 2008 and 2009, PJM made several filings at FERC proposing various revisions to its capacity market, or Reliability Pricing Model (RPM), including the determination of the cost-of-new-entry (CONE), which is an important component in determining the price paid to capacity resources in PJM. PJM also proposed revisions relating to the participation of energy efficiency and demand resources, and market power and mitigation rules. Some of these matters are still pending at FERC. While recent RPM design changes have not yet had a material effect on our financial results, we cannot predict the outcome of the issues still pending or on any capacity market design changes that result from new regulatory requirements. Such changes could have a material impact on our financial results.

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. In September 2008, FERC dismissed the complaint and in October 2008, the complainants requested a rehearing at FERC. FERC denied rehearing and ultimately the case was appealed and is pending before the United States Court of Appeals for the District of Columbia. 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.

In April 2009, the Attorney General of Connecticut, the Connecticut Department of Public Utilities and Office of Consumer Counsel (together, the Connecticut Parties) filed complaints at FERC alleging improper energy bidding behavior since December 1, 2006 by generators located in New York that also received capacity payments within ISO-New England. In May 2009, the Connecticut Parties filed an amended complaint asserting that Constellation Energy Commodities Group, Inc. (CCG) and others received capacity payments while never intending to perform as capacity resources. The revised allegations assert that certain generators engaged in "economic withholding" by submitting energy bids at or near the offer cap. Since December 2006, CCG has received approximately $7 million in payments for capacity offered into ISO-New England associated with Constellation Energy's nuclear facilities located in NY. In August 2009, FERC issued an order setting this matter for a public hearing before an ALJ to determine the intent of the capacity suppliers (including CCG) in making their energy offers in ISO-New England. CCG is participating in the administrative hearing, which is ongoing and has maintained its

adherence to all applicable rules and regulations relating to the market activity. However, we cannot predict the outcome of the FERC hearing or any potential liability that CCG may incur.

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, both in the states and 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.

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 and cyber-security 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.

Given the increasing concern over the security of the country's energy infrastructure, there could be future rules or regulations related to the operation and security requirements of our generating facilities and electric and gas transmission and distribution systems, which could have a material impact on our operations and financial results.

The United States Congress and the Commodity Futures Trading Commission (CFTC) are evaluating additional laws and regulations for the derivatives markets, including position limits and eliminating regulatory exemptions for hedging activity. We are unable to determine the final form any regulations or new laws may take, but such laws or regulations could have a material effect on our business.

Regulatory agencies that have jurisdiction over our businesses, including the FERC and CFTC, possess broad enforcement and investigative authority to ensure well functioning markets and to prohibit market manipulation or violations of the agencies' rules or orders. These agencies also possess significant civil penalty authority, including in the case of FERC and the CFTC, the authority to impose a penalty of up to $1 million per day per violation. We are committed to a culture of compliance and ensuring compliance with all applicable rules, laws and orders. Nonetheless, the regulatory agencies engage in either public or non-public investigations in response to allegations of wrongdoing and we may be involved in certain market activities that become subject to investigations. Even where no wrongdoing is found, the process of participating in a regulatory investigation could have a material effect on our business.

Weather conditions in the different regions of North America influence the financial results of our Generation and NewEnergy businesses. 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.

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 the Regulation—Maryland PSC—Revenue Decoupling, Regulated Electric Business—Revenue Decoupling and Regulated Gas Business—Revenue Decoupling sections.

A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our NewEnergy 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 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.

We discuss details of our environmental matters in Note 12 to Consolidated Financial Statements and Item 1. Business—Environmental Matters section. 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.

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

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, in Note 1 to Consolidated Financial Statements.

We utilize a variety of derivative instruments in order to manage commodity price risk, interest rate risk, and foreign currency risk. Because of the extensive nature of the accounting requirements that govern both accounting treatment and documentation, as well as the complexity of the transactions within its scope, management is required 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 the derivative accounting requirements, failure to meet these requirements, even inadvertently, could require the use of a different accounting treatment for the affected transactions. In addition, interpretations of these accounting requirements continue to evolve, and future changes in accounting requirements also could affect our financial statements materially. We discuss derivatives and hedging activities in more detail in Note 1 and Note 13 to Consolidated Financial Statements.

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 and applying that definition to each individual contract. If a contract is not a derivative, we cannot apply derivative accounting, 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 derivative accounting, which provides for several possible accounting treatments as discussed more fully under Accounting Treatment below. 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.

We are permitted several possible accounting treatments for derivatives that meet all of the applicable requirements. Mark-to-market is 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, both at the time of designation and on an ongoing basis.

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

	Recognition and Measurement

Accounting Treatment	Recognition and Measurement
Accounting Treatment	Balance Sheet	Income Statement

Mark-to-market	¨ Derivative asset or liability recorded at fair value	¨ Changes in fair value recognized in earnings

Cash flow hedge	¨ Derivative asset or liability recorded at fair value	¨ Ineffective changes in fair value recognized in earnings
	¨ Effective changes in fair value recognized in accumulated other comprehensive income	¨ Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurring

Fair value hedge	¨ Derivative asset or liability recorded at fair value	¨ Changes in fair value recognized in earnings
	¨ Book value of hedged asset or liability adjusted for changes in its fair value	¨ Changes in fair value of hedged asset or liability recognized in earnings

NPNS (accrual)	¨ Fair value not recorded	¨ Changes in fair value not recognized in earnings
	¨ Accounts receivable or accounts payable recorded when derivative settles	¨ 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, 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, we are not required to designate and account for all such contracts identically. We generally elect accrual or hedge accounting for our physical energy delivery activities (Generation and NewEnergy businesses) 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:

As a result of making these judgments, the selection of accounting treatments for derivatives 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 (AOCI). Additionally, the selection of accounting treatment also affects the amount and timing of the recognition of earnings. The following table summarizes these impacts:

	Accounting Treatment

Effect of Changes in Fair Value on:	Accounting Treatment
Effect of Changes in Fair Value on:	Mark-to-market	Cash Flow Hedge	Fair Value Hedge	NPNS

Assets 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 impact

AOCI	• No impact	• Increase or decrease for effective portion of hedge	• No impact	• No impact

Earnings 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 impact

Earnings at settlement	• No impact	• Amounts in AOCI reclassified to earnings when hedged forecasted transaction affects earnings or when the forecasted transaction becomes probable of not occurring	• Hedged margin recognized in earnings	• Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed

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. 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 in Note 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.

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

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

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. 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 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.

We evaluate unproved property at least annually to determine if it is impaired. 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.

We evaluate our equity-method and cost-method investments (for example, CENG, UNE, Constellation Energy Partners LLC (CEP) and partnerships that own power projects) to determine whether or not they are impaired. The standard for determining whether an impairment must be recorded is whether the investment has experienced an "other than a temporary" decline in value.

The evaluation and measurement of investment impairments involves the same uncertainties as described above for long-lived assets that we own directly. 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, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value.

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 nuclear joint ventures and CEP. These issues include environmental and legislative initiatives as well as events that will impact the viability of new nuclear development. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements and Item 1A. Risk Factors sections. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired.

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, and any losses recognized could be material.

Our available for sale investments in debt and equity securities are subject to impairment evaluations. Our most significant available for sale securities were the nuclear decommissioning trust fund assets. However, upon the completion of our transaction with EDF on November 6, 2009, we no longer reflect the nuclear decommissioning trust fund assets on our Consolidated Balance Sheets. To the extent that CENG impairs its nuclear decommissioning trust fund assets, we will report our share of the impairment as part of our equity investment earnings in CENG.

We 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 through November 6, 2009 for which the market value was below book value, the decline in fair value for these securities was considered other than temporary, and the securities were written down to fair value.

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We do not amortize goodwill. We 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.

On November 6, 2009, we sold a 49.99% membership interest in CENG, our nuclear generation and operation business. The following summarizes where we disclose the significant impacts of this transaction on us:

On October 30, 2009, as part of the order approving our transaction with EDF, the Maryland PSC required Constellation Energy to fund a one-time distribution rate credit to be given to BGE residential customers before the end of March 2010 totaling $110.5 million, or approximately $100 per customer. In December 2009, BGE filed a tariff with the Maryland PSC stating BGE would give residential customers a distribution rate credit of exactly $100 per customer. We recorded the total credit of $112.4 million in the fourth quarter of 2009 and will apply it to customer bills in the first quarter of 2010 as required under the order. Constellation Energy made a $66 million equity contribution to BGE in December 2009 to fund the after-tax amount of the rate credit as required by the Maryland PSC order approving the transaction with EDF. We discuss BGE's residential customer rate credit in Note 2 to Consolidated Financial Statements.

On October 30, 2009, as part of the order approving our transaction with EDF, the Maryland PSC required Constellation Energy to provide a $250 million cash capital contribution to BGE by no later than June 30, 2010. Constellation Energy made this contribution in December 2009.

In July 2009, we acquired CLT Efficient Technologies Group (CLT), an energy services company.

On November 30, 2009, we signed an agreement to acquire the Criterion wind project in Garrett County, Maryland.

We discuss these acquisitions in more detail in Note 15 to Consolidated Financial Statements.

We discuss these divestitures and the gas supply agreement in more detail in the Note 2 to Consolidated Financial Statements.

Throughout 2009, we incurred merger termination and strategic alternatives costs related to the terminated merger with MidAmerican Energy Holdings Company (MidAmerican) in 2008, the conversion of our Series A Preferred Stock into a note, the transactions related to EDF, and other strategic alternatives costs. We discuss costs related to the mergers and strategic alternatives in more detail in Note 2 to Consolidated Financial Statements.

Throughout 2009, we recorded impairment losses and other costs on certain of our equity method investments, investments in equity securities and other assets. We discuss these charges in more detail in the Note 2 to Consolidated Financial Statements.

During 2009, we incurred workforce reduction costs primarily related to the divestiture of a majority of our international commodities operation as well as other smaller restructurings elsewhere in our organization. We recognized a $12.6 million pre-tax charge in 2009 related to the elimination of approximately 180 positions. We expect all of these restructurings will be completed within 12 months from the program's initiation. We discuss our workforce reduction costs in more detail in Note 2 to Consolidated Financial Statements.

In the fourth quarter of 2009, we redeemed our Zero Coupon Senior Notes early and recognized a pre-tax loss of $16.0 million.

In February 2010, we retired certain of our 7.00% Notes due April 1, 2012 as part of a cash tender offer launched in January 2010 and issued call notices to retire certain tax exempt notes.

We discuss these transactions in more detail in Note 9 to Consolidated Financial Statements.

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 (expense), fixed charges, and income taxes are discussed in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section.

As discussed in Item 1 Business—Overview section and in the Strategy and Significant Events sections, Constellation Energy's 2009 and 2008 operating results were materially impacted by a number of significant events, transactions, and changes in our strategic direction. The impact of these items has affected the comparability of our 2009 and 2008 results to prior periods and will alter Constellation Energy's operating results in the future. In this section, we highlight the 2009 and 2008 impacts of these items.

		2009			2008			2007


		(In millions, after-tax)
Net income (loss):
	Generation	$	4,766.7		$	(357.7	)	$	303.5
	NewEnergy		(348.2	)		(1,011.4	)		380.0
	Regulated electric		79.1			11.1			107.9
	Regulated gas		25.5			40.4			32.0
	Other nonregulated		(19.7	)		(0.8	)		11.0

Income (Loss) from continuing operations and before cumulative effects of changes in accounting principles			4,503.4			(1,318.4	)		834.4
Loss from discontinued operations			—			—			(0.9	)

Net Income (Loss)		$	4,503.4		$	(1,318.4	)	$	833.5

Net Income (Loss) attributable to common stock		$	4,443.4		$	(1,314.4	)	$	821.5

Change from prior year		$	5,757.8		$	(2,135.9	)

Our total net income attributable to common stock for 2009 improved compared to 2008 by $5.8 billion, or $29.53 per share, mostly because of the following:

	Increase/(Decrease) 2009 vs. 2008


(in millions, after-tax)
Generation gross margin	$	27
NewEnergy gross margin		(134	)
Absence of sale of NewEnergy upstream gas assets		(16	)
NewEnergy hedge ineffectiveness		84
Absence of NewEnergy credit loss—coal supplier bankruptcy		33
Regulated businesses, excluding the effects of the 2008 Maryland settlement agreement and the 2009 residential customer credit		10
Other nonregulated businesses		(8	)
Total change in Other Items Included in Operations per table below		5,763
All other changes		(1	)

Total Change	$	5,758

Our total net loss attributable to common stock for 2008 deteriorated compared to 2007 by $2.1 billion, or $11.84 per share, mostly because of the following:

	Increase/(Decrease) 2008 vs. 2007


(In millions, after-tax)
Generation gross margin	$	149
NewEnergy gross margin		(211	)
Sale of NewEnergy upstream gas assets		16
Absence of 2007 sale of CEP LLC equity		(39	)
NewEnergy hedge ineffectiveness		(26	)
NewEnergy credit loss—coal supplier bankruptcy		(33	)
Synthetic fuel facilities		(9	)
Other nonregulated businesses		(12	)
Interest and investment income		(35	)
Total change in Other Items Included in Operations per table below		(1,966	)
All other changes		30

Total Change	$	(2,136	)

		2009			2008			2007


		(In millions, after-tax)
	Gain on sale of 49.99% interest in CENG	$	4,456.1		$	—		$	—
	Amortization of basis difference in CENG		(17.8	)		—			—
	International commodities operation and gas trading operation¹		(371.9	)		—			—
	Impairment losses and other costs		(96.2	)		(468.4	)		(12.2	)
	Merger termination and strategic alternatives costs		(13.8	)		(1,204.4	)		—
	Loss on redemption of Zero Coupon Senior Notes		(10.0	)		—			—
	BGE residential customer rate credit		(67.1	)		—			—
	Maryland settlement credit		—			(110.5	)		—
	Impairment of nuclear decommissioning trust assets		(46.8	)		(82.0	)		—
	Emission allowance write down, net		—			(28.7	)		—
	Non-qualifying hedges		—			(70.1	)		2.0
	Credit facility amendment/termination fees		(37.7	)		—			—
	Workforce reduction costs		(9.3	)		(13.4	)		(1.4	)

Total Other Items		$	3,785.5		$	(1,977.5	)	$	(11.6	)

Change from prior year		$	5,763.0		$	(1,965.9	)

Our Generation business is discussed in detail in Item 1. Business—Operating Segments section.

We present the results of this business based on the assumption that we have hedged 100% of generation output and fuel for generation. The assumption is based on executing hedges at prevailing market prices with the NewEnergy business. Taking into account previously executed hedges at the end of each fiscal year, we ensure that the Generation business is fully hedged by the NewEnergy business for the next year. Therefore, all commodity price risk is managed by and presented in the results of our NewEnergy business as discussed below. Generally, changes in the results of our Generation business during the period are due to changes in the level of output from the generating assets.

		2009			2008			2007


		(In millions)
Revenues		$	2,774.2		$	2,958.5		$	2,477.8
Fuel and purchased energy expenses			(692.0	)		(916.1	)		(681.8	)

Gross margin			2,082.2			2,042.4			1,796.0
Operating expenses			(1,008.4	)		(969.1	)		(946.6	)
Impairment losses and other costs			—			(14.0	)		(20.2	)
Workforce reduction costs			—			(6.1	)		(2.3	)
Merger termination and strategic alternatives costs			(101.8	)		(742.3	)		—
Depreciation, depletion, and amortization			(176.8	)		(174.3	)		(169.8	)
Accretion of asset retirement obligations			(62.1	)		(67.9	)		(67.9	)
Taxes other than income taxes			(67.4	)		(69.9	)		(62.6	)
Equity investment earnings			0.2			26.8			28.8
Gain on sale of 49.99% interest in CENG			7,445.6			—			—

Income from Operations		$	8,111.5		$	25.6		$	555.4

Income (Loss) from continuing operations and before cumulative effects of changes in accounting principles (after-tax)		$	4,766.7		$	(357.7	)	$	303.5
	Loss from discontinued operations (after-tax)		—			—			(0.9	)

Net Income (Loss)		$	4,766.7		$	(357.7	)	$	302.6

Net Income (Loss) attributable to common stock		$	4,766.7		$	(357.7	)	$	302.6

Change from prior year		$	5,124.4		$	(660.3	)

Other Items Included in Operations (after-tax):
	Gain on sale of 49.99% interest in CENG	$	4,456.1		$	—		$	—
	Amortization of basis difference in CENG		(17.8	)		—			—
	Impairment losses and other costs		—			(8.3	)		(12.2	)
	Merger termination and strategic alternatives costs		(9.7	)		(742.3	)		—
	Loss on redemption of Zero Coupon Senior Notes		(10.0	)		—			—
	Impairment of nuclear decommissioning trust assets		(46.8	)		(82.0	)		—
	Credit facility amendment/termination fees		(13.7	)		—			—
	Workforce reduction costs		—			(3.7	)		(1.4	)

Total Other Items		$	4,358.1		$	(836.3	)	$	(13.6	)

Change from prior year		$	5,194.4		$	(822.7	)

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.

Prior to November 6, 2009, CENG was a 100% owned subsidiary, and we consolidated its financial results within our Consolidated Statements of Income (Loss). On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF, and we deconsolidated CENG. Accordingly, for the period from November 6, 2009 through December 31, 2009, we ceased recording CENG's financial results and began to record equity investment earnings from CENG as well as the

effect of our PPA and other transactions with CENG. We discuss our transaction with EDF in more detail in Note 2 to Consolidated Financial Statements.

For the period from January 1, 2009 through November 6, 2009, our Generation results included the following financial results of CENG:

As a result of deconsolidation, we expect that our future Generation results will differ from historical results primarily due to the following factors:

Additionally, we will record our 50.01% share of CENG's financial results and amortization of the CENG basis difference in the "Equity Investment (Losses) Earnings" line in our Consolidated Statements of Income (Loss). We discuss the accounting for our retained investment in CENG in more detail in Note 2 to Consolidated Financial Statements.

Our Generation revenues decreased $184.3 million in 2009 compared to 2008 and increased $480.7 million in 2008 compared to 2007 primarily due to the following:

Our Generation fuel and purchased energy expenses decreased $224.1 million in 2009 compared to 2008 and increased $234.3 million in 2008 compared to 2007 primarily due to the following:

Our Generation business operating expenses increased $39.3 million during 2009 as compared to 2008 due to higher performance-based labor and benefit costs of $74.5 million, partially offset by lower non-labor operating expenses of $35.2 million.

Our Generation business operating expenses increased $22.5 million during 2008 compared to 2007 due to higher non-labor operating expenses of $43.2 million, partially offset by lower performance-based labor and benefit costs of $20.7 million.

For 2010, we expect a decrease in operating expenses as a result of the deconsolidation of CENG on November 6, 2009. We discuss this impact further in the Effects of Transaction with EDF on Statement of Income (Loss) section.

Our impairment losses and other costs are discussed in more detail in Note 2 to Consolidated Financial Statements.

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

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

Our Generation business incurred higher depreciation, depletion and amortization expenses of $2.5 million during 2009 compared to 2008 due to an increase of $12.0 million in depreciation on our non-nuclear generating assets primarily related to environmental additions at our Brandon Shores coal-fired generating plant that went into service in the fourth quarter of 2009 partially offset by a $9.5 million decrease in depreciation on our nuclear generating assets resulting from the deconsolidation of CENG on November 6, 2009.

Our Generation business incurred higher depreciation, depletion, and amortization expenses of $4.5 million in 2008 compared to 2007 due to an increase of $3.2 million in depreciation on our existing generating facilities and $1.3 million of depreciation on our West Valley generating plant, which was acquired in June 2008.

Our Generation business incurred lower accretion of asset retirement obligations expense of $5.8 million in 2009 compared to 2008, which represents the absence of costs from deconsolidating CENG on November 6, 2009.

Our Generation business incurred lower taxes other than income taxes of $2.5 million in 2009 compared to 2008, primarily due to lower property taxes on our nuclear generating assets resulting from the deconsolidation of CENG on November 6, 2009.

Our Generation business incurred higher taxes other than income taxes of $7.3 million in 2008 compared to 2007 due to a $4.7 million increase in property taxes on our generating facilities, the absence of a $2.0 million property tax refund received in 2007, and $0.6 million in property taxes on our West Valley generating plant, which was acquired in June 2008.

During 2009, our equity investment earnings decreased $26.6 million from 2008 primarily due to $18.9 million of higher losses from our investment in UNE and $12.0 million of lower earnings on investments in power projects, partially offset by $4.3 million in earnings related to our investment in CENG.

Equity investment earnings decreased $2.0 million in 2008 compared to 2007 primarily due to $7.8 million of higher losses from our investment in UNE partially offset by $5.8 million of higher earnings on investments in power projects.

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF. As a result of this sale, we recognized a $7.4 billion pre-tax gain. We discuss this transaction in Note 2 to Consolidated Financial Statements.

Our NewEnergy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our NewEnergy business in Item 1. Business—Competition section.

Our NewEnergy business focuses on delivery of physical, customer- oriented energy products and services to energy producers and consumers, manages the risk and optimizes the value of our owned and contracted generation assets and NewEnergy activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy limited risk capital. Our NewEnergy business actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions.

At the beginning of 2009, we outlined various strategic initiatives to reduce risk for our NewEnergy business. As of December 31, 2009, these initiatives have been completed. We discuss our current strategy in more detail in the Strategy section.

The execution of our strategy in the future may be affected by 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.

We record NewEnergy 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 the Critical Accounting Policies section and Note 1 to Consolidated Financial Statements.

		2009			2008			2007


		(In millions)
Revenues		$	11,509.2		$	15,851.7		$	18,074.1
Fuel and purchased energy expenses			(10,430.0	)		(14,812.2	)		(16,458.8	)

Gross margin			1,079.2			1,039.5			1,615.3
Operating expenses			(763.6	)		(932.7	)		(998.1	)
Impairment losses and other costs			(98.1	)		(727.8	)		—
Workforce reduction costs			(12.6	)		(9.5	)		—
Merger termination and strategic alternatives costs			(44.0	)		(462.1	)		—
Depreciation, depletion, and amortization			(82.5	)		(118.7	)		(105.0	)
Accretion of asset retirement obligations			(0.2	)		(0.5	)		(0.4	)
Taxes other than income taxes			(41.2	)		(54.4	)		(47.7	)
Equity investment (losses) earnings			(6.3	)		49.6			(20.7	)
(Loss) gain on divestitures			(468.8	)		25.5			—

(Loss) Income from Operations		$	(438.1	)	$	(1,191.1	)	$	443.4

Net (Loss) Income		$	(348.2	)	$	(1,011.4	)	$	380.0

Net (Loss) Income attributable to common stock		$	(402.3	)	$	(994.2	)	$	381.3

Change from prior year		$	591.9		$	(1,375.5	)

Other Items Included in Operations (after-tax):
	International commodities operation and gas trading operation (1)	$	(371.9	)	$	—		$	—
	Impairment losses and other costs		(84.7	)		(460.1	)		—
	Merger termination and strategic alternatives costs		(4.1	)		(462.1	)		—
	Emission allowance write-down, net		—			(28.7	)		—
	Non-qualifying hedges		—			(70.1	)		2.0
	Credit facility amendment/termination fees		(24.0	)		—			—
	Workforce reduction costs		(9.3	)		(5.8	)		—

Total Other Items		$	(494.0	)	$	(1,026.8	)	$	2.0

Change from prior year		$	532.8		$	(1,028.8	)

Our NewEnergy revenues decreased $4,342.5 million in 2009 compared to 2008 and decreased $2,222.4 million in 2008 compared to 2007 primarily due to the following:

	2009 vs. 2008			2008 vs. 2007


	(In millions)
Decrease in wholesale mark-to-market revenues due to changes in power and gas prices	$	(215	)	$	(403	)
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested		(647	)		—
Decrease in contract prices and volume of business primarily related to our divested international coal and freight operation		—			(281	)
Increase in contract prices and volumes related to our domestic coal operation		280			—
Realization of lower prices and volume of business at our gas trading operation, which we have divested, and absence of revenue due to the sales of certain of our upstream gas properties in 2008		(283	)		—
Lower volumes of wholesale and retail load, partially offset by higher contract prices		(3,523	)		—
Realization of higher contract prices on wholesale and retail load		—			475
All other (for 2008 vs. 2007, substantially all due to change in gas procurement activities) (1)		45			(2,013	)

Total decrease in NewEnergy revenues	$	(4,343	)	$	(2,222	)

Our NewEnergy fuel and purchased energy expenses decreased $4,382.2 million in 2009 compared to 2008 and decreased

	2009 vs. 2008			2008 vs. 2007


	(In millions)
Change in mark-to-market expenses related to international coal purchase contracts	$	218		$	(108	)
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested		(615	)		—
Decrease in contract prices and volume of business primarily related to our international coal and freight operation		—			(238	)
Realization of lower volumes at our gas trading operations, which we have divested		(220	)		—
Increase in contract prices and volume related to our domestic coal operation		259			—
Lower volumes on wholesale and retail power purchases		(4,008	)		—
Realization of higher contract prices on wholesale and retail purchases		—			780
Decrease in synfuels expenses due to expiration of tax credits in 2007		—			(141	)
All other (for 2008 vs. 2007, substantially all due to change in gas procurement activities)		(16	)		(1,940	)

Total decrease in NewEnergy fuel and purchased energy expenses	$	(4,382	)	$	(1,647	)

Mark-to-market results include net gains and losses from origination, risk management, and trading 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 Policies section and in Note 1 to Consolidated Financial Statements.

The nature of our operations and the use of mark-to-market accounting for certain activities create fluctuations in mark-to-market earnings. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in the Risk Management section. The primary factors that cause fluctuations in our mark-to-market results are:

During 2009, we focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short- and interim-term liquidity requirements. These actions may impact the future results of the NewEnergy 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 NewEnergy business 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, while in general the underlying physical transactions related to these activities 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.

			2009			2008			2007


			(In millions)
Unrealized mark-to-market results
	Origination gains		$	—		$	73.8		$	41.9
	Risk management and trading—mark-to-market
		Unrealized changes in fair value		(212.3	)		159.8			500.8
		Changes in valuation techniques		—			—			—
		Reclassification of settled contracts to realized		(265.4	)		48.2			(369.3	)

	Total risk management and trading—mark-to-market			(477.7	)		208.0			131.5

Total unrealized mark-to-market*				(477.7	)		281.8			173.4
Realized mark-to-market				265.4			(48.2	)		369.3

Total mark-to-market results**			$	(212.3	)	$	233.6		$	542.7

Total mark-to-market results decreased $445.9 million during the year ended December 31, 2009 compared to the same period of 2008. The period-to-period variance in

unrealized changes in fair value was due to decreased unrealized risk management and trading results of $372.1 million and the decrease in origination gains of $73.8 million. We discuss the decrease in origination gains below.

The decrease in risk management and trading results of $372.1 million was primarily due to:

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 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:

We did not record any origination gains during 2009. During 2008, our NewEnergy business amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these amendments, the revised contracts became derivatives subject to mark-to-market accounting. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the unrealized mark-to-market results table above.

During 2007, our NewEnergy business amended certain nonderivative power sales contracts such that the new contracts became derivatives subject to mark-to-market accounting. 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, 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.

The recognition of origination gains is generally dependent on sufficient available 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, 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.

At December 31,	2009			2008


	(In millions)
Current assets	$	639.1		$	1,465.0
Noncurrent assets		633.9			851.8

Total assets		1,273.0			2,316.8

Current liabilities		632.6			1,241.8
Noncurrent liabilities		674.1			1,115.0

Total liabilities		1,306.7			2,356.8

Net derivative position	$	(33.7	)	$	(40.0	)

Composition of net derivative exposure:
Hedges	$	(591.0	)	$	(1,837.6	)
Mark-to-market		524.3			1,485.9
Net cash collateral included in derivative balances		33.0			311.7

Net derivative position	$	(33.7	)	$	(40.0	)

Derivative balances above include noncurrent assets related to our Generation business of $35.8 million and $55.9 million for the periods ended December 31, 2009 and December 31, 2008, respectively. Derivative balances related to our Generation business consist of interest rate contracts accounted for as fair value hedges.

As discussed in our Critical Accounting Policies section, 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 in Note 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 in Note 13 to Consolidated Financial Statements.

The decrease of $1,246.6 million in our net derivative liability subject to hedge accounting since December 31, 2008 primarily was due to $1,896 million of realization of out-of-the-money cash-flow hedges at the time the forecasted transaction occurred, partially offset by $649 million of increased unrealized losses on our remaining out-of-the-money cash-flow hedge positions primarily related to decreases in power, natural gas, and coal prices during 2009.

The following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during 2009 and 2008:

		2009						2008


		(In millions)
Fair value beginning of year					$	1,485.9				$	673.0
Changes in fair value recorded in earnings
	Origination gains	$	—					$	73.8
	Unrealized changes in fair value		(212.3	)					159.8
	Changes in valuation techniques		—						—
	Reclassification of settled contracts to realized		(265.4	)					48.2

Total changes in fair value						(477.7	)				281.8
Changes in value of exchange-listed futures and options						97.8					571.3
Net change in premiums on options						84.9					19.2
Contracts acquired						(35.8	)				—
Dedesignated contracts and other changes in fair value						(630.8	)				(59.4	)

Fair value at end of year					$	524.3				$	1,485.9

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

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

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 are as follows as of December 31, 2009:

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 NewEnergy business, 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.

Our NewEnergy business operating expenses decreased $169.1 million during 2009 as compared to 2008 due to lower performance-based labor and benefit costs of $126.0 million and lower non-labor operating expenses of $43.1 million, part of which represents the absence of costs from the divestitures completed in 2009.

Our NewEnergy business operating expenses decreased $65.4 million during 2008 compared to 2007 due to lower performance-based labor and benefit costs of $106.2 million, partially offset by higher non-labor operating expenses of $40.8 million, which included approximately $32 million of higher bad debt expense.

Our impairment losses and other costs are discussed in more detail in Note 2 to Consolidated Financial Statements.

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

Our NewEnergy business incurred costs related to the amortization of credit facility amendment fees in connection with the EDF transaction. These costs are classified as part of "Other income (expense)" in our Consolidated Statements of Income (Loss).

Our NewEnergy business incurred lower depreciation, depletion and amortization expenses of $36.2 million during 2009 compared to 2008 due to the absence of depletion expenses of $43.0 million as a result of divestitures made in 2008 in our upstream gas operations, partially offset by an increase of $6.8 million in other amortization primarily related to computer software placed in service in the fourth quarter of 2008.

Our NewEnergy business incurred higher depreciation, depletion, and amortization expenses of $13.7 million in 2008 compared to 2007 mostly due to an increase of $23.3 million in depletion expenses related to our upstream natural gas operations as a result of increased drilling and production, partially offset by a decrease of $9.6 million in other depreciation due to the cessation of operations at our synfuel facilities in December 2007.

Our NewEnergy business incurred lower taxes other than income taxes of $13.2 million in 2009 compared to 2008, due to $8.1 million of lower gross receipts taxes resulting from a significant decrease in retail load revenues and $5.8 million of lower production taxes related to our upstream gas producing properties, partially offset by $0.7 million of higher property, franchise, and other taxes.

Our NewEnergy business incurred higher taxes other than income taxes of $6.7 million in 2008 compared to 2007, due to $3.1 million of higher gross receipts taxes resulting from higher retail load revenues, $1.4 million of higher production taxes related to our upstream gas producing properties, and $2.2 million of higher property, franchise, and other taxes.

During 2009, our equity investment earnings decreased $55.9 million from 2008 due to $39.1 million of lower earnings from our shipping joint venture as a result of the sale of our interests in July 2009, $12.3 million of lower earnings from our investment in CEP, and the absence of $4.5 million in earnings from investments in synfuel facilities.

Equity investment earnings increased $70.3 million in 2008 compared to 2007 due to $38.0 million of higher earnings from our shipping joint venture primarily resulting from a gain on the sale of a dry bulk vessel in the third quarter of 2008, $30.7 million in higher earnings from investments in synfuel facilities, and $1.6 million of higher earnings from our investment in CEP.

During 2009, we sold a majority of our international commodities operation, our Houston-based gas trading operation, certain other trading operations, a uranium market participant, and an energy project, and we recognized a pre-tax loss of $468.8 million.

During 2008, we recognized net gains of $25.5 million, including a $14.3 million gain, net of the noncontrolling 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 these divestitures in more detail in Note 2 to Consolidated Financial Statements.

Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section.

		2009			2008			2007


		(In millions)
Revenues		$	2,820.7		$	2,679.7		$	2,455.7
Electricity purchased for resale expenses			(1,840.9	)		(1,880.1	)		(1,500.4	)
Operations and maintenance expenses			(399.0	)		(380.5	)		(376.1	)
Workforce reduction costs			—			(4.6	)		—
Depreciation and amortization			(218.1	)		(184.2	)		(187.4	)
Taxes other than income taxes			(142.9	)		(139.1	)		(140.2	)

Income from Operations		$	219.8		$	91.2		$	251.6

Net Income		$	79.1		$	11.1		$	107.9

Net Income attributable to common stock		$	68.9		$	1.1		$	97.9

	Other Items Included in Operations (after-tax):
	Residential customer rate credit	$	(56.7	)	$	—		$	—
	Maryland settlement credit		—			(110.5	)		—
	Workforce reduction costs		—			(2.8	)		—

Total Other Items		$	(56.7	)	$	(113.3	)	$	—

Net income attributable to common stock from the regulated electric business increased $67.8 million in 2009 compared to 2008, mostly due to a $53.8 million after-tax decrease in credits provided to customers.

Net income attributable to common stock 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 $110.5 million after-tax.

The changes in electric revenues in 2009 and 2008 compared to the respective prior year were caused by:

	2009 vs. 2008			2008 vs. 2007


	(In millions)
Distribution volumes	$	(6.3	)	$	(15.0	)
Residential customer rate credit		(95.0	)		—
Nuclear decommissioning charges		18.7			—
Smart Energy Savers Program^SM surcharges		29.3			—
Maryland settlement credit		189.1			(189.1	)
Revenue decoupling		22.7			12.5
Standard offer service		(33.2	)		79.4
Rate stabilization credits		—			287.3
Rate stabilization recovery		(2.7	)		43.1
Financing credits		3.4			(9.1	)
Senate Bill 1 credits		6.9			3.3

Total change in electric revenues from electric system sales		132.9			212.4
Other		8.1			11.6

Total change in electric revenues	$	141.0		$	224.0

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 2009 and 2008 compared to the respective prior year were:

In 2009, we distributed less electricity to residential customers due to decreased usage per customer, partially offset by colder winter weather and an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer.

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.

On October 30, 2009, the Maryland PSC issued an order approving Constellation Energy's transaction with EDF. Among other things, the order required Constellation Energy to fund a one-time distribution rate credit for BGE residential customers before the end of March 2010 totaling $110.5 million, or approximately $100 per customer, for which BGE recorded a liability in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating BGE would give residential customers a rate credit of exactly $100 per customer. As a result, BGE accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. The portion of this total credit allocated to residential electric customers was $95.0 million pre-tax. This credit was accrued in the fourth quarter of 2009 and will be applied to BGE residential electric customer bills in the first quarter of 2010.

Effective January 1, 2009, BGE and Calvert Cliffs Nuclear Power Plant Inc. (Calvert Cliffs) mutually agreed to terminate the decommissioning funds collection agent agreement, which was effective from July 1, 2000 to December 31, 2008. As a result, BGE ceased transferring funds to provide for the decommissioning of Calvert Cliffs Unit 1 and Unit 2. Calvert Cliffs retains the obligation to provide adequate assurances of funding pursuant to Nuclear Regulatory Commission requirements. Under the 2008 Maryland settlement agreement, BGE will continue to provide certain credits to residential customers and assess certain charges to all customers relating to decommissioning.

Beginning in 2009, the Maryland PSC approved customer surcharges through which BGE recovers costs associated with certain programs designed to help BGE manage peak demand and encourage customer energy conservation.

As discussed in more detail in Note 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.

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 the

Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section.

Standard offer service revenues decreased in 2009 compared to 2008 mostly due to lower standard offer service volumes, partially offset by higher standard offer service rates.

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.

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 as a result of the expiration of the rate stabilization plans.

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

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.

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 2008 Maryland settlement agreement, which is discussed in more detail in Note 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 2009 compared to 2008 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.

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 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:

BGE's actual costs for electricity purchased for resale decreased $39.2 million for 2009 compared to 2008, primarily due to lower standard offer service volumes, partially offset by higher standard offer service rates.

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.

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. 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 the Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section.

In late June 2007, we began recovering previously deferred amounts from customers. We recovered $59.0 million per year in 2009 and 2008 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.

Regulated electric operations and maintenance expenses increased $18.5 million in 2009 compared to 2008, primarily due to increased uncollectible accounts receivable expense of $5.1 million and the impact of inflation on other costs of $8.0 million.

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.

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.

Regulated electric depreciation and amortization expense increased $33.9 million during 2009, compared to 2008, primarily due to $43.3 million in increased amortization expense associated with the Smart Energy Savers Program^SM and additional property placed in service in 2009, partially offset by $18.7 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.

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 in Note 2 to Consolidated Financial Statements. This decrease was partially offset by additional property placed in service in 2008.

Taxes other than income taxes increased $3.8 million during 2009 compared to 2008, primarily due to the impact of $94.1 million pre-tax in lower customer credits on franchise taxes.

Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section.

		2009			2008			2007


		(In millions)
Revenues		$	758.3		$	1,024.0		$	962.8
Gas purchased for resale expenses			(449.9	)		(694.5	)		(639.8	)
Operations and maintenance expenses			(160.9	)		(157.3	)		(157.5	)
Workforce reduction costs			—			(1.8	)		—
Depreciation and amortization			(44.0	)		(43.7	)		(46.8	)
Taxes other than income taxes			(34.9	)		(35.4	)		(36.1	)

Income from Operations		$	68.6		$	91.3		$	82.6

Net Income		$	25.5		$	40.4		$	32.0

Net Income attributable to common stock		$	22.5		$	37.2		$	28.8

Other Items Included in Operations (after-tax):
	Residential customer rate credit	$	(10.4	)	$	—		$	—
	Workforce reduction costs		—			(1.0	)		—

Total Other Items		$	(10.4	)	$	(1.0	)	$	—

Net income attributable to common stock from the regulated gas business decreased $14.7 million in 2009 compared to 2008, primarily due to the accrual of a customer rate credit of $10.4 million after-tax and increased operations and maintenance expenses of $2.2 million after-tax.

Net income attributable to common stock 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.

The changes in gas revenues in 2009 and 2008 compared to the respective prior year were caused by:

The percentage changes in our distribution volumes, by type of customer, in 2009 and 2008 compared to the respective prior year were:

In 2009, we distributed more gas to residential customers due to colder winter weather. We distributed less gas to commercial customers due to decreased usage per customer, partially offset by an increased number of customers and colder weather. We distributed more gas to industrial customers mostly due to increased usage per customer, partially offset by a decreased number of customers.

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.

On October 30, 2009, the Maryland PSC issued an order approving Constellation Energy's transaction with EDF. Among other things, the order required Constellation Energy to fund a one-time distribution rate credit for BGE residential customers totaling $110.5 million, or approximately $100 per customer, for which BGE recorded a liability in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating BGE would give residential customers a rate credit of exactly $100 per customer. As a result, BGE accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. The portion of this total credit allocated to residential gas customers was $17.4 million pre-tax. This credit was accrued in the fourth quarter of 2009 and will be applied to BGE residential gas customer bills in the first quarter of 2010.

Beginning February 2009, the Maryland PSC approved a customer surcharge through which BGE recovers costs associated with certain programs designed to help BGE encourage customer conservation.

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, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

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 decreased in 2009 compared to 2008 because we sold less gas at lower prices.

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

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 decreased in 2009 compared to 2008 because we sold less gas at lower prices.

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.

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 decreased $244.6 million in 2009 compared to 2008 because we purchased less gas at lower prices.

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

Regulated gas operation and maintenance expenses increased $3.6 million during 2009 compared to 2008, primarily due to increased uncollectible accounts receivable expense of $2.0 million.

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.

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 in Note 2 to Consolidated Financial Statements.

		2009			2008			2007


		(In millions)
Revenues		$	14.4		$	16.1		$	25.9
Operating expenses			56.5			54.3			26.4
Impairment losses and other costs			(26.6	)		—			—
Workforce reduction costs			—			(0.2	)		—
Depreciation and amortization			(67.7	)		(62.3	)		(48.8	)
Taxes other than income taxes			(4.0	)		(3.0	)		(2.3	)

(Loss) Income from Operations		$	(27.4	)	$	4.9		$	1.2

Net (Loss) Income		$	(19.7	)	$	(0.8	)	$	11.0

Net (Loss) Income attributable to common stock		$	(12.4	)	$	(0.8	)	$	10.9

Other Items Included In Operations (after-tax):
	Impairment losses and other costs	$	(11.5	)	$	—		$	—
	Workforce reduction costs		—			(0.1	)		—

	Total Other Items	$	(11.5	)	$	(0.1	)	$	—

Net loss attributable to common stock for 2009 increased $11.6 million compared to 2008 primarily due to increased impairment losses and other costs due to an impairment of a district chilled water energy plant of $7.1 million after-tax and reduction for noncontrolling interest, a write-off of an uncollectible advance to an affiliate of $4.3 million after-tax, and higher depreciation and amortization expense of $3.2 million after-tax as a result of increased property additions during 2008.

Net loss attributable to common stock exceeded net income attributable to common stock by $11.7 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 recur in 2008 and due to increased depreciation and amortization of $8.1 million after-tax.

In 2009, we had other expenses of $140.7 million and, in 2008, we had other expenses of $69.5 million. The $71.2 million increase in 2009 compared to 2008 is mostly due to higher credit facility costs, including amortization of amendment fees.

In 2008, we had other expenses of $69.5 million and, in 2007 we had other income of $157.4 million. The $226.9 million decrease in 2008 compared to 2007 is mostly due to lower interest and investment income of $75 million 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 decreased $4.2 million in 2009 compared to 2008 primarily due to decreases in both interest and investment income of $4.2 million.

Other income at BGE increased $2.7 million in 2008 compared to 2007 primarily due to an increase in equity funds capitalized on increased construction work in progress in 2008.

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.

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.

Income tax expense increased $3,065.1 million during 2009 compared to 2008 mostly due to higher income before income taxes due to the recognition of the $7.4 billion pre-tax gain on closing the transaction to sell a 49.99% membership interest in CENG. Additionally, there was lower income before income taxes for 2008, primarily due to approximately $1.2 billion of non-tax deductible merger termination and strategic alternative costs. However, in 2009, certain of these costs became tax deductible as a result of closing the EDF transaction and we recorded a tax benefit for these items in 2009.

BGE's income tax expense increased $43.1 million during 2009, mostly due to higher pre-tax income. For 2008, BGE had a lower effective tax rate as a result of a reduction in its 2008 taxable income due to the impact of certain provisions of the 2008 Maryland settlement agreement, which increased the relative impact of the favorable permanent tax adjustments on its effective tax rate.

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

At December 31, 2009, the total projected benefit obligations of our qualified and nonqualified pension plans exceeded the fair value of our qualified pension plan assets by $411.7 million. At December 31, 2008, the total projected benefit obligations of our qualified and nonqualified pension plans exceeded the fair value of our qualified pension plan assets by $936.7 million. The $525.0 million improvement in the funded status of our pension plans in 2009 primarily reflects the following:

These increases were partially offset by normal growth in the projected benefit obligations of our qualified and nonqualified pension plans.

At December 31, 2009, our accumulated post retirement benefit obligations totaled $322.3 million compared to $415.4 million at December 31, 2008. The $93.1 million reduction in obligations for these unfunded plans primarily reflects the November 6, 2009 separation of CENG postretirement benefit plans with accumulated post retirement benefit obligations totaling $98.6 million.

Our other postemployment benefit obligation declined $9.3 million from $59.9 million at December 31, 2008 to $50.6 million as of December 31, 2009, primarily due to the deconsolidation of CENG on November 6, 2009.

We discuss our defined benefit plans in further detail in Note 7 to Consolidated Financial Statements.

Our allowance for uncollectible accounts receivable decreased $80.0 million from $240.6 million at December 31, 2008 to $160.6 million at December 31, 2009, primarily related to a decrease of $93.3 million in our NewEnergy business, partially offset by an increase of $13.0 million at our regulated electric and gas businesses.

The decrease in allowance for uncollectible accounts receivable from our NewEnergy business is primarily driven by the write-off of the accounts receivable and related allowance for uncollectible accounts receivable balances for certain customers that were established primarily during 2008 when these counterparties encountered financial difficulties. There was no earnings impact associated with these write-offs in 2009.

The increase in allowance for uncollectible accounts receivable from our regulated electric and gas businesses is primarily driven by a Maryland PSC ruling in the second quarter of 2009 and the economic downturn which continues to cause a decreased ability of customers to pay their utility bills. The Maryland PSC ruling in the second quarter of 2009 delayed BGE's ability to terminate service to customers with arrearages and required BGE to offer those customers the option to enter into extended payment plans. BGE ceased entering into these extended plans on September 25, 2009.

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

The completion of the sale of a 49.99% membership interest in CENG to EDF on November 6, 2009 had the following significant effects on our Consolidated Balance Sheets:

Additionally, we deconsolidated CENG for financial reporting purposes. The deconsolidation had significant effects on our Consolidated Balance Sheets including the following:

The following table summarizes our 2009 cash flows by business segment, as well as our consolidated cash flows for 2009, 2008, and 2007.

			2009 Segment Cash Flows												Consolidated Cash Flows

			Generation			NewEnergy			Regulated			Eliminations, Holding Company and Other			2009			2008			2007

			(In millions)
Operating Activities
	Net income (loss)		$	4,766.7		$	(348.2	)	$	104.6		$	(19.7	)	$	4,503.4		$	(1,318.4	)	$	833.5
	Non-cash merger termination and strategic alternatives costs			89.5			38.7			—			—			128.2			541.8			—
	Derivative contracts classified as financing activities (1)			—			1,138.3			—			—			1,138.3			(107.2	)		32.2
	Gain on sale of 49.99% membership interest in CENG			(7,445.6	)		—			—			—			(7,445.6	)		—			—
	Loss (gain) on divestitures			—			468.8			—			—			468.8			(38.1	)		—
	Accrual of BGE residential customer credit			—			—			112.4			—			112.4			—			—
	Impairment losses and other costs			—			98.1			—			26.6			124.7			741.8			20.2
	Other non-cash adjustments to net (loss) income			2,325.3			(222.1	)		525.0			132.8			2,761.0			602.9			493.0
	Changes in working capital
		Derivative assets and liabilities, excluding collateral		3.5			421.9			(0.1	)		—			425.3			(757.9	)		(138.2	)
		Net collateral and margin		—			1,519.2			3.6			—			1,522.8			(960.3	)		49.6
		Other changes		(22.0	)		(316.7	)		11.2			1,094.5			767.0			93.6			(242.4	)
	Defined benefit obligations (2)			—			—			—			—			(287.2	)		(20.8	)		(53.6	)
	Other			5.1			(43.2	)		68.6			141.2			171.7			(38.5	)		(53.3	)

Net cash (used in) provided by operating activities				(277.5	)		2,754.8			825.3			1,375.4			4,390.8			(1,261.1	)		941.0

Investing Activities
	Investments in property, plant and equipment			(1,013.4	)		(118.9	)		(372.6	)		(24.8	)		(1,529.7	)		(1,934.1	)		(1,295.7	)
	Asset acquisitions and business combinations, net of cash acquired			—			(20.8	)		—			(20.3	)		(41.1	)		(315.3	)		(347.5	)
	Change in cash pool			1,957.1			(1,513.4	)		(165.9	)		(277.8	)		—			—			—
	Contributions to nuclear decommissioning trust funds			(18.7	)		—			—			—			(18.7	)		(18.7	)		(8.8	)
	Investments in joint ventures			(201.6	)		—			—			—			(201.6	)		—			—
	Issuances of loans receivable			—			—			—			—			—			—			(19.0	)
	Proceeds from sale of 49.99% membership interest in CENG			3,528.7			—			—			—			3,528.7			—			—
	Proceeds from sale of investments and other assets			—			57.1			—			31.2			88.3			446.3			13.9
	Contract and portfolio acquisitions			—			(2,153.7	)		—			—			(2,153.7	)		—			(474.2	)
	(Increase) decrease in restricted funds (3)			—			(0.1	)		(0.6	)		1,004.0			1,003.3			(942.8	)		(109.9	)
	Other investments			(11.3	)		11.5			(12.0	)		11.9			0.1			21.7			(45.3	)

Net cash provided by (used in) investing activities				4,240.8			(3,738.3	)		(551.1	)		724.2			675.6			(2,742.9	)		(2,286.5	)

Cash flows from operating activities plus cash flows from investing activities			$	3,963.3		$	(983.5	)	$	274.2		$	2,099.6			5,066.4			(4,004.0	)		(1,345.5	)

Financing Activities (2)
	Net (repayment) issuance of debt															(2,660.4	)		3,447.7			(33.1	)
	Debt and credit facility costs															(98.4	)		(104.8	)		—
	Proceeds from issuance of common stock															33.9			17.6			65.1
	Common stock dividends paid															(228.0	)		(336.3	)		(306.0	)
	BGE preference stock dividends paid															(13.2	)		(13.2	)		(13.2	)
	Reacquisition of common stock															—			(16.2	)		(409.5	)
	Proceeds from contract and portfolio acquisitions															2,263.1			—			847.8
	Derivative contracts classified as financing activities (1)															(1,138.3	)		107.2			(32.2	)
	Other															12.7			8.3			33.4

Net cash (used in) provided by financing activities																(1,828.6	)		3,110.3			152.3

Net increase (decrease) in cash and cash equivalents															$	3,237.8		$	(893.7	)	$	(1,193.2	)

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

Cash provided by operating activities was $4.4 billion in 2009 compared to cash used in operating activities of $1.3 billion in 2008. This $5.7 billion increase in cash flows was primarily due to:

	December 31,

	2009			2008

	(In millions)
Net collateral and margin posted, beginning of year	$	(1,445.6	)	$	(485.3	)
Return of collateral held associated with nonderivative contracts		(17.0	)		(26.3	)
Net return of (additional) collateral posted associated with nonderivative contracts		336.3			(330.5	)
Return of (additional) initial and variation margin posted on exchange-traded transactions recorded in accounts receivable		924.8			(94.0	)
Return of (additional) fair value net cash collateral posted (netted against derivative assets/liabilities)*		278.7			(509.5	)

Change in net collateral and margin posted		1,522.8			(960.3	)

Net collateral and margin held, end of year	$	77.2		$	(1,445.6	)

The $1.5 billion decrease in net collateral and margin posted during 2009 primarily reflects the following:

Cash used in operating activities was $1.3 billion in 2008 compared to cash provided by operating activities of $0.9 billion in 2007. This $2.2 billion decrease in cash flows was primarily due to:

Cash provided by investing activities was $0.7 billion in 2009 compared to cash used of $2.7 billion in 2008. The $3.4 billion increase in cash provided in 2009 compared to 2008 was primarily due to:

Cash used in investing activities was $2.7 billion in 2008 compared to $2.3 billion in 2007. The $0.4 billion 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 $0.5 billion of cash used in 2007 for contract and portfolio acquisitions, which we discuss in more detail below, and approximately $0.4 billion 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 was recorded as additional proceeds for EDF's purchase of 49.99% membership interest in CENG in 2009.

Cash used in financing activities was $1.8 billion in 2009 compared to cash provided of $3.1 billion in 2008. The increase in cash used for financing activities of $4.9 billion was primarily due to:

This increase in cash used for financing activities was partially offset by $2.3 billion of cash provided from contract and portfolio acquisitions as a component of our strategic divestitures. As a result of the structure of the divestitures of a majority of our international commodities, Houston-based gas trading and other trading operations, we are required to present financing cash inflows for out-of-the-money contracts on a gross basis separate from investing cash outflows for in-the-money contracts executed simultaneously. We discuss our divestitures in more detail in Note 2 to Consolidated Financial Statements. There was no such activity in 2008.

Cash provided by financing activities was $3.1 billion in 2008 compared to $0.2 billion in 2007. The increase of $2.9 billion was primarily due to the issuance of:

During 2009 and 2007, our NewEnergy 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 $109.4 million in 2009 due to the execution of total return swaps to assist in the execution of our divestitures of our international commodities and Houston-based gas trading operations and $373.6 million in 2007 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:

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. 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 in Note 2 to Consolidated Financial Statements.

Prior to November 6, 2009, we recorded 100% of the revenues, expenses, and cash flows from CENG and the nuclear plants it owns because we wholly owned this entity. On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF, and we deconsolidated CENG. Accordingly, for the period from November 6, 2009 through December 31, 2009, we ceased recording CENG's cash flows and began to record cash flows from our PPA and other transactions with CENG. In the future, we will record cash flows from any distributions received from CENG based on our 50.01% ownership interest, and we may be required to make capital contributions to help fund CENG's capital program.

As a result of deconsolidation, we expect that our future Generation business cash flows will differ from historical cash flows primarily due to the following factors:

In addition, we entered into a power services agency agreement (PSA) and an administrative service agreement (ASA) with CENG. The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and will recognize average annual revenue of approximately $16 million.

The ASA is a one year agreement that is renewable annually under which we will provide administrative support services to CENG for a fee of approximately $66 million for 2010. The level of fees for administrative support services will be subject to change in future years based on the level of services provided. The charges under these agreements are intended to represent the actual cost of the services provided to CENG from us.

We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Independent credit rating agencies rate Constellation Energy's and BGE's fixed- income securities. These ratings affect how much it will cost us to sell securities and, in certain cases, our ability to access capital markets to sell securities. Generally, the better the rating, the lower the cost of the securities to us when we sell them. 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 flows and to total capitalization.

At the date of this report, the senior unsecured debt and commercial paper credit ratings for Constellation Energy and BGE were as follows:

The Constellation Energy and BGE ratings in the above table reflect stable outlooks by all the credit rating agencies. If any of these 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.

We discuss the potential effect of a ratings downgrade in the Collateral section.

We discuss the potential effect of a ratings downgrade on our ability to maintain ongoing compliance with financial ratios in our existing credit agreements in Note 8 to Consolidated Financial Statements.

As a condition to the October 2009 Maryland PSC order approving our transaction with EDF, Constellation Energy and BGE were required to implement "ring fencing" measures to provide bankruptcy protection and credit rating separation of BGE from Constellation Energy. We completed the implementation of these measures in February 2010.

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.

In addition to cash generated from 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, many of 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 NewEnergy business.

The primary drivers of our use of liquidity have been our capital expenditure requirements and collateral requirements associated with hedging our generating assets and hedging our NewEnergy business in both power and gas. As part of our strategic initiatives, we have modified the structure of certain transactions and terminated others in order to reduce these collateral requirements. 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.

We discuss our, and BGE's, credit facilities in detail in Note 8 to the Consolidated Financial Statements.

The following tables provide a summary of our net available liquidity at December 31, 2009 and 2008.

	As of December 31, 2009

	Constellation Energy			BGE		Total Consolidated

	(In billions)
Credit facilities (1)	$	3.5		$	0.6	$	4.1
Less: Letters of credit issued		(1.7	)		—		(1.7	)
Less: Cash drawn on credit facilities		—			—		—

Undrawn facilities		1.8			0.6		2.4
Less: Commercial paper outstanding		—			—		—

Net available facilities		1.8			0.6		2.4
Add: Cash		3.4			—		3.4
Less: Reserved cash (2)		(1.3	)		—		(1.3	)

Cash and facility liquidity		3.9			0.6		4.5
Add: EDF put arrangement		1.1			—		1.1

Net available liquidity	$	5.0		$	0.6	$	5.6

During 2009, net available liquidity increased $3.3 billion due to the following:

Through our efforts to reduce risk and more actively manage our liquidity, we significantly improved our net available liquidity during 2009. Specifically, we executed on our planned divestitures, significantly reduced the activities of our NewEnergy business, and restructured and terminated existing transactions and amended certain agreements, all of which have led to lower collateral requirements. Through December 31, 2009, we received substantially all of the $1 billion of total net collateral expected to be returned upon the completion of our divestitures. In addition, we added new credit facilities during 2009 that are discussed in more detail in Note 8 to Consolidated Financial Statements.

During 2009, our cash balance increased $3.2 billion. The increase is largely a result of the proceeds from the EDF transaction and strong cash flows in our core businesses, partially offset by bond repayments and the retirement of debt prior to maturity. We discuss our cash flows in more detail earlier in the Cash Flows section and the EDF transaction in the Significant Events section. We intend to use the funds from the EDF transaction to pay the taxes owed on the transaction, to fulfill our $1.0 billion voluntary debt reduction commitment, to fund strategic growth initiatives, and for other general corporate purposes. We discuss our voluntary debt reduction in more detail in Note 9 to Consolidated Financial Statements.

In connection with its approval of the EDF transaction, we were required by the Maryland PSC to implement "ring fencing" measures designed to provide bankruptcy protection and credit rating separation of BGE from Constellation Energy. We discuss the Maryland PSC order in more detail in the Regulation- Maryland section. These ring fencing measures were implemented in 2010, and as a result BGE no longer participates in the Constellation Energy cash pool.

In December 2009, Constellation Energy contributed approximately $316 million of equity ($250.0 million capital contribution and $65.9 million for a residential customer rate credit) to BGE as required by the Maryland PSC order approving the EDF transaction. As a result of BGE terminating participation in the Constellation Energy cash pool, this equity contribution will be reflected in the cash balance of BGE beginning in January 2010.

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.

We believe that the actions that we have taken and our current net available liquidity will be sufficient to support our ongoing liquidity requirements. Our liquidity projections include assumptions for commodity price changes, which are subject to significant volatility, and we are exposed to certain operational risks that could have a significant impact on our liquidity. We discuss items that could negatively impact our liquidity in the Item 1A. Risk Factors section.

Constellation Energy's collateral requirements generally arise from its NewEnergy business as a result of its participation in certain organized markets, such as Independent System Operators (ISOs) or financial exchanges, as well as from our margining on over-the-counter (OTC) contracts.

To support wholesale and retail power NewEnergy obligations and our limited trading activities, Constellation Energy posts collateral to ISOs. Forward hedging of our Generation and NewEnergy businesses creates the need to transact with exchanges such as New York Mercantile Exchange and Intercontinental Exchange. 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 of 2008 as a result of changes in exchange rules and decreased during the fourth quarter of 2008 as a result of portfolio risk reduction and downsizing activities.

During 2009, our initial margin requirements continued to decrease. In March 2009 and April 2009, we closed-out our exchange positions related to our international commodities operation and Houston-based gas trading operation, respectively, which reduced our margin posted with each exchange with which we transact.

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

There are certain inherent asymmetries relating to the use of collateral that create liquidity requirements for our Generation and NewEnergy businesses. These asymmetries arise from 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:

Finally, collateral types may asymmetrically impact our liquidity. For example, in margining with over-the-counter counterparties, we may post letter of credit (LC) collateral for an out-of-the money counterparty. However, we may receive LC collateral when we are in-the-money with a counterparty. Posting LCs reduces our liquidity while the receipt of LC collateral does not increase our liquidity.

Customers of our NewEnergy 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, 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:

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 facilities in the Available Sources of Funding section.

Our actual consolidated capital requirements for the years 2007 through 2009, along with the estimated annual amount for 2010, are shown in the following table.

Capital requirements for 2010 and 2011 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:

Please see the Forward Looking Statements and Item 1A. Risk Factors sections.

			2007		2008		2009		2010 (Estimate)


			(In billions)
Generation and Other Capital Requirements:
		Major Environmental	$	0.2	$	0.5	$	0.3	$	0.1
		Maintenance		0.5		0.5		0.6		0.1
		Growth		—		0.4		0.2		0.1

	Total Generation and Other Capital Requirements			0.7		1.4		1.1		0.3

NewEnergy Capital Requirements:
	Maintenance			0.1		0.1		—		0.1
	Growth			0.5		0.2		0.1		0.1

Total NewEnergy Capital Requirements				0.6		0.3		0.1		0.2

Regulated Capital Requirements:
	Electric / Gas Distribution			0.3		0.4		0.3		0.4
	Electric Transmission			0.1		0.1		—		0.1
	Smart Energy Savers^SM Initiatives			—		—		0.1		0.1

Total Regulated Capital Requirements				0.4		0.5		0.4		0.6

Total Capital Requirements			$	1.7	$	2.2	$	1.6	$	1.1

Eligible capital projects are shown net of anticipated investment tax credits or grants.

As of the date of this report, we estimate our 2011 capital requirements will be approximately $1.0 billion.

Our Generation and NewEnergy businesses' capital requirements consist of its continuing requirements, including expenditures for:

In addition, in December 2009, we were selected by the State of Maryland to construct, own, operate and maintain a 17 MW solar photovoltaic power installation in Emmitsburg, Maryland. We expect this project to cost us approximately $60 million and be completed by December 2012. Renewable electricity produced by the system will be purchased by the State of Maryland at the site of Mount St. Mary's University under a 20-year solar power purchase agreement.

In 2009, we signed an agreement to acquire the 70 MW Criterion wind project in Garrett County, Maryland. The completed cost of this project is expected to be approximately $140 million. We expect to close this transaction, subject to certain conditions, in the first quarter of 2010 and expect commercial operation of the facility in the fall of 2010.

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.

In July 2009, BGE filed with the Maryland PSC a proposal for a comprehensive smart grid initiative. The proposal includes the planned installation of 2 million residential and commercial electric and gas smart meters. We expect the total cost of the program to be approximately $480 million. In October 2009, the United States Department of Energy selected BGE as a recipient of $200 million in federal funding for our smart grid initiative. This grant allows BGE to be reimbursed for smart grid expenditures up to $200 million, substantially reducing the total cost of this initiative. However, the United States Department of Energy may withhold funding until approval is obtained from the Maryland PSC. The Maryland PSC held hearings on this proposed program in late 2009 and expects to issue an order in the first quarter of 2010. If BGE's proposal is approved by the Maryland PSC, BGE plans to proceed with this program as soon as practical.

We expect to fund the capital requirements of our Generation and NewEnergy businesses 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 Generation and NewEnergy businesses develop typically require substantial capital investment. Many of the qualifying facilities and independent power projects that we have an interest in as well as our upstream properties 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.

We expect to fund capital expenditures associated with our regulated electric and gas businesses through a combination of internally and externally generated cash. To the extent that internally generated cash is not sufficient to meet those requirements, we would seek additional funding from the short-term and long-term 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. In December 2009, BGE received a $250 million capital contribution from Constellation Energy as required by the October 2009 order from the Maryland PSC approving our transaction with EDF. At that time, Constellation Energy also funded the after-tax cost of $66 million of the residential customer credits required by the same order.

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 our Generation and NewEnergy 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, 2009 in the following table:

				Payments

				2010			2011- 2012			2013- 2014			Thereafter			Total

				(In millions)
Contractual Payment Obligations
	Long-term debt: (1)
		Nonregulated
			Principal	$	0.4		$	751.4		$	20.0		$	1,903.0		$	2,674.8
			Interest		152.1			299.6			241.9			2,904.3			3,597.9

		Total			152.5			1,051.0			261.9			4,807.3			6,272.7
		BGE
			Principal		56.5			254.2			537.0			1,352.4			2,200.1
			Interest		130.5			247.2			194.9			1,253.4			1,826.0

		Total			187.0			501.4			731.9			2,605.8			4,026.1
	BGE preference stock				—			—			—			190.0			190.0
	Operating leases (2)
		Operating leases, gross			226.0			435.1			375.0			396.4			1,432.5
		Sublease rentals			(56.5	)		(102.1	)		(56.3	)		(114.8	)		(329.7	)

		Operating leases, net			169.5			333.0			318.7			281.6			1,102.8
	Purchase obligations: (3)
		Purchased capacity and energy (4)			160.9			303.5			107.7			208.7			780.8
		Purchased energy from CENG			534.7			1,513.3			2,249.8			—			4,297.8
		Fuel and transportation			540.5			437.5			94.3			217.9			1,290.2
		Other			77.9			39.3			6.6			6.7			130.5
	Other noncurrent liabilities:
		Uncertain tax positions liability			—			143.8			67.7			18.3			229.8
		Pension benefits (5)			45.8			217.5			203.7			—			467.0
		Postretirement and post employment benefits (6)			32.3			72.9			82.8			185.0			373.0

Total contractual payment obligations				$	1,901.1		$	4,613.2		$	4,125.1		$	8,521.3		$	19,160.7

(1): Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $207 million early through remarketing features. Interest on variable rate debt is included based on forward curve for interest rates.
(2): Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 to Consolidated Financial Statements.
(3): Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations which may differ from actual purchases.
(4): Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.
(5): Amounts related to pension benefits reflect our current 5-year forecast for contributions for our qualified pension plans and participant payments for our nonqualified pension plans. Refer to Note 7 to Consolidated Financial Statements for more detail on our pension plans.
(6): Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded in our Consolidated Balance Sheets as discussed in Note 7 to Consolidated Financial Statements.

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, 2009, we have no material off-balance sheet arrangements, including:

At December 31, 2009, Constellation Energy had a total face amount of $10.4 billion in guarantees outstanding, of which $9.4 billion related to our NewEnergy 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 $2 billion at December 31, 2009, which represents the total amount the parent company could be required to fund based on December 31, 2009 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 in Note 12 to Consolidated Financial Statements and our significant variable interests in Note 4 to Consolidated Financial Statements.

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 five 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 and risk concentration 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 economic value, 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.

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, senior management is responsible for monitoring the key risks, facilitated by a Risk Management Group (RMG). Our RMG is responsible for 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 Executive Officer, and consists of our Chief Risk Officer, Chief Financial Officer, Vice Chairman, General Counsel, Chief Human Resources Officer, head of Corporate Strategy and Development, head of Corporate Affairs, Public, and Environmental Policy 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 unit on an appropriate course of action.

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.

Credit Risk Management is responsible for managing the risk of loss inherent in the business units stemming from counterparty or customer failures and adverse market events that effect counterparty creditworthiness. This group supports the business units by establishing credit relationships with various wholesale counterparties and retail customers and facilitating market liquidity with credit limits and appropriate contractual credit terms and conditions. Credit risk managers are responsible for managing credit risk associated with our business activities, including establishing limits and contractual structures, as well as establishing and enforcing credit policies.

Market Risk Management is responsible for effectively identifying, quantifying, monitoring, and reporting on impacts of market risk, to include price volatility, correlations, volume uncertainty, market liquidity, interest rate and currency exposure on company businesses. The market risk group also enforces the

Market Risk policies and ensures compliance with these policies, including the monitoring, analyzing, and escalating of market risk controls. This group also develops market risk measurement tools, such as stress and scenario tests, gross margin-at-risk, and assists the businesses in implementing market strategies with the highest benefits.

Collateral Risk Management is responsible for providing an integrated view on credit, market, and company liquidity risks to facilitate Treasury's management of the Company's collateral and overall liquidity position. This group's responsibilities include measuring and monitoring collateral flows, downgrade collateral needs, and collateral use across the Company. Additionally, this group forecasts expected collateral requirements as well as 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. The group also works closely with the Treasury function to plan for expected and contingent liquidity needs based on the Company's long-term business plan.

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.

Corporate Audit assists in ensuring that controls put in place by management to mitigate the risks of the business are adequate and functioning appropriately. This group supports the risk assessment process including the analysis of inherent and residual risk, performs risk-based audits as approved by the Audit Committee of the Board of Directors, and supports the improvement of the effectiveness and efficiency of key business processes.

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.

We manage risks across all of our businesses. We summarize below the risks we manage within each of our businesses.

Our Generation and NewEnergy businesses are 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.

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 Business section. As a result of this process, BGE's exposure to market price risk is limited, and at December 31, 2009, 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 in Note 13 to Consolidated Financial Statements.

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.

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 to Consolidated Financial Statements. At December 31, 2009, 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.

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; operational risk and funding liquidity risk. As previously noted, these risks may be common to more than one of our businesses. We discuss each of these primary risk exposure categories separately below.

We are exposed to the impact of market fluctuations in the price and transportation costs of power, natural gas, coal, and other related commodities. These risks arise from our ownership and

operation of power plants, our retail and wholesale 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 Generation and NewEnergy businesses, and if we do not hedge the associated financial exposure, this commodity price volatility could adversely affect our economic value or earnings. These factors include:

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

Additionally, we have fuel requirements that are subject to future changes in coal, natural gas, 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 Generation and NewEnergy businesses, including electricity sales, fuel and energy purchases, emission credits, interest rate, foreign currency, weather, 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 portion of forecasted transactions hedged may vary based upon management's assessment of market conditions, 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 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, historical price relationships, 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 related 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, generating plants, or proprietary positions taken by the Company. We assess and monitor market risk with a variety of tools, including EVaR, VaR, scenario analysis, and stress testing.

EVaR measures the potential pre-tax loss in the fair value of the Generation and NewEnergy businesses due to changes in market risk factors. EVaR is a one-day value-at-risk measure calculated at a 95% confidence level assuming a standard normal distribution of prices over the most recent rolling 3-month period. EVaR includes all positions over a forward rolling 60-month time horizon that expose us to market price risk, regardless of accounting treatment and business line.

Positions included in EVaR are comprised of all positions, regardless of accounting treatment, that create market risk including:

We include the positions related to physical assets to provide a more complete presentation of our commodity market risk exposures. EVaR includes illiquid products and positions for which there is limited price discovery. Modeling the positions in our Generation and NewEnergy businesses involves a number of assumptions, and includes projections of generation, emission rates and costs, customer load growth, load response to weather, and customer response to competitive supply. Changes in our forecast or management estimates will affect the fair value of these positions in a manner not captured by EVaR.

EVaR reflects the risk of loss due to market prices under normal market conditions. An inherent limitation of our value-at-risk measures is the reliance on historical prices. A sudden shift in market conditions can cause the future behavior of market prices to differ materially from the past. We use stress tests and scenario analysis to better understand extreme events as a complement to EVaR. This includes exposure to unlikely but plausible events in abnormal markets, sensitivity to changes in management projections of customer demand or forecasted generation output, and price sensitivity to illiquid points and regional basis spreads.

EVaR is monitored daily and is subject to regional and overall guidelines for the NewEnergy business. We place guidelines on the risk associated with illiquid delivery locations and regional basis within our NewEnergy business. Additionally, we monitor generation plant hedge ratios relative to guidelines specified by management. Stress tests and scenario analysis are conducted regularly and the results, trends, and explanations are reviewed by senior management and risk committees.

The EVaR amounts below represent the potential pre-tax change in the fair values of our Generation and NewEnergy businesses positions over a one-day holding period.

N/A—Average, high, and low amounts for 2008 are not available as we did not begin computing those categories of EVaR until the fourth quarter of 2008.

At December 31, 2009, our EVaR was approximately $73 million, which represents a 46% decline from its level of $136 million on December 31, 2008, mainly due to de-risking activities and the closing of the EDF transaction in the last quarter of the year.

VaR measures the potential pre-tax loss in the fair value of mark-to-market energy contracts due to changes in market risk factors. VaR is a one-day value-at-risk measure calculated at a 95% confidence level assuming a standard normal distribution of prices over the most recent rolling 3-month period. VaR includes all positions subject to mark-to-market accounting, including contracts that hedge the economics of NewEnergy nonderivative power and fuel contracts, but which do not receive hedge accounting treatment, but also contracts designated for trading. Thus, the positions for which we monitor VaR are included within, and are not incremental, to the positions subject to EVaR.

VaR and EVaR have similar limitations. VaR may include some products and positions for which there is limited price discovery or market depth. The modeling of option positions included in VaR involves a number of assumptions and approximations. An inherent limitation of our VaR measures is the reliance on historical prices. A sudden shift in market conditions can cause the future behavior of market prices to differ materially from that of the past.

The VaR amounts below represent the potential pre-tax loss in the fair value of our NewEnergy business positions subject to mark-to-market accounting, including both trading and non-trading activities, over one and ten-day holding periods.

During 2009, 99% Confidence Level, One-Day Holding Period mark-to-market VaR represented in the table below ranged between a high of $55.5 million in the beginning of the year and a low of $5.0 million towards the end of the year. Despite the wide range of values during 2009, mark-to-market VaR has been declining steadily throughout the year, consistent with our de-risking efforts. While de-risking activities were the main contributor to the declining level of mark-to-market VaR, this metric will continue to be impacted by the volatility of commodity prices and by the size of mark-to-market positions of our non-trading activities.

For the year ended December 31,		2009		2008


		(In millions)
99% Confidence Level, One-Day Holding Period
	Year end	$	8.0	$	19.7
	Average		18.1		26.1
	High		55.5		38.0
	Low		5.0		19.7
95% Confidence Level, One-Day Holding Period
	Year end	$	6.1	$	15.0
	Average		13.8		19.9
	High		42.2		28.9
	Low		3.8		15.0
95% Confidence Level, Ten-Day Holding Period
	Year end	$	19.2	$	47.5
	Average		43.7		62.8
	High		133.6		91.5
	Low		12.0		47.5

Constellation Energy's proprietary trading activities are substantially reduced from previous years and are now immaterial. These activities continue to be managed with daily VaR limits, stop loss limits and position limits.

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. In July 2009, we terminated an interest rate swap relating to $50 million of the $450 million of fixed-rate debt. Including the $400.0 million in interest rate swaps, approximately 13% of our long-term debt is floating-rate.

We discuss our use of derivative instruments to manage our interest rate risk in more detail in Note 13 to Consolidated Financial Statements.

The following table provides information about our debt obligations that are sensitive to interest rate changes:

We are exposed to price fluctuations in financial markets primarily through our pension plan assets. In 2009, our actual gain on pension plan assets was $217.6 million. We describe our pension funding requirements in more detail in Note 7 to Consolidated Financial Statements.

Our Generation and NewEnergy businesses are 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 2009, our exposure to foreign currency risk was not material. We manage our exposure to foreign currency exchange rate risk using a foreign currency hedging program. We will continue to have limited exposure to the Canadian dollar due to our Canadian gas and power operations.

We are exposed to credit risk through our Generation and NewEnergy businesses and BGE's operations. Credit risk is the loss that may result from counterparties' nonperformance and retail customer accounts receivable and forward value payment risk arising from contracted power and gas supply agreements. We evaluate our credit risk as discussed below.

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 NewEnergy business 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, 2009 and 2008, counterparties in our NewEnergy credit portfolio had the following public credit ratings:

Our exposure to "Not Rated" counterparties was $1.5 billion at December 31, 2009 and December 31, 2008.

Many of our not rated 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 $1.2 billion or 81% of the exposure to unrated counterparties was rated investment grade equivalent at December 31, 2009 and approximately $0.9 billion or 60% was rated investment grade equivalent at December 31, 2008. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings.

Our total exposure, net of collateral, to counterparties across our entire wholesale portfolio is $2.8 billion as of December 31, 2009. The top ten counterparties account for approximately 52% of our total exposure with approximately 5% of that exposure being non-investment grade.

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 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.

As of December 31, 2009, our total exposure of $2.8 billion, net of collateral, includes accrual positions and derivatives. This total exposure has declined significantly from the $4.5 billion as of December 31, 2008, as a result of our de-risking activities and divestitures and changes in commodity prices. Of our $2.8 billion total exposure at December 31, 2009, less than $1 billion is recorded on our Consolidated Balance Sheets.

Immediately preceding the EDF transaction, we entered into long term PPA agreements with CENG, creating a counterparty exposure (net of payables owed) exceeding 10% of our total credit exposure. We discuss our counterparty credit risk in more detail in Note 1 to Consolidated Financial Statements. Other than the exposure to CENG, no single counterparty concentration comprises more than 10% of the total exposures recorded on our Consolidated Balance Sheets as of December 31, 2009.

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 we 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.

We are exposed to retail credit risk through our NewEnergy electricity and natural gas supply activities, which serve commercial and industrial companies and governmental entities, 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, geographic, or industry concentrations. In 2008, reserve levels had been increased across our retail businesses due to indicators of deteriorating credit quality and macroeconomic slowdown. In the first half of 2009, the overall incidence of customer bankruptcies increased, but had moderated to more historic levels by year end. Sectors most susceptible to financial stress were concentrated in consumer cyclical industries and commercial real estate. As a result, we have increased our reserve levels accordingly. We have also augmented our credit risk organization with a dedicated credit workout function.

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 contingent on amounts approved by the Maryland PSC in customer rates and, therefore is not guaranteed and BGE is exposed to these potential losses and related carrying costs.

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, have direct and indirect ownership interests in, and/or 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.

CENG, an entity in which we own a 50.01% membership interest, owns nuclear plants. These nuclear plants produce electricity at a relatively low marginal cost. Nine Mile Point Unit 2 and the Ginna facility sell approximately 90% of their respective output under unit-contingent power purchase agreements (CENG has 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, CENG may have to purchase replacement power at potentially higher prices to meet their obligations, which could have a material adverse impact on CENG's and 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.

Funding liquidity risk relates to the ability to fund current and future obligations of the company given variability in collateral requirements as well as variability around working capital requirements and other cash flows that may affect our liquidity. To assess funding liquidity risk, we distinguish between sources and uses of liquidity. Sources of liquidity include projected net available cash, the unused capacity available from our credit facilities, and any availability under the EDF put arrangement through December 31, 2010. Uses include expected and contingent collateral requirements as well as any unexpected variation of cash flows from projected levels. We define contingent requirements to be any incremental or decremental requirements to expected requirement levels.

To manage liquidity risk, we quantify sources of liquidity and the expected and contingent uses of liquidity both over a short-term and long-term horizon. Contingent uses of liquidity are determined by stress-testing our portfolio using a simulation of extreme, adverse price stresses and measuring their combined impact on collateral needs and on cash flows related to losses due to market and credit risk. Liquidity stresses related to operational risks (weather, plant outages) and other business risks not directly linked to price moves are assessed on a regular basis using scenario analysis. Results of the liquidity assessment are shared regularly with senior management.

Liquidity risk assessment has been integrated into our strategic planning process. Expected and contingent funding needs implied by the business plans of our various business units are first aggregated and compared to available liquidity sources over the planning horizon. Capital and liquidity sources are then allocated to business units based on their business plans, taking into account the cost of providing liquidity. We believe that this integrated view on sources and uses of liquidity allows us to ensure proper funding of the business in accordance with our business plan.

The information required by this item with respect to market risk is set forth in Item 7 of Part II of this Form 10-K under the heading Risk Management.

Operation		Closing Date


Majority of our international commodities operation		March 2009

Gas and other trading operations (1)		April 2009

Uranium market participant		June 2009

Shipping joint venture investment		August 2009

District energy facility		December 2009

	2009 vs. 2008			2008 vs. 2007


	(In millions)
Change due to (lower) higher energy prices for the output of our generating plants	$	(185	)	$	398
Decrease in volume of output from nuclear generating assets primarily due to the deconsolidation of CENG		(150	)		—
Increase in volume of output due to lower planned and unplanned outages at our generating plants		152			19
Increase in volume of output from generating plants and acquisition of West Valley generating plant		—			62
All other		(1	)		2

Total (decrease) increase in Generation revenues	$	(184	)	$	481




Residential	(1.3	)%	(2.6	)%
Commercial	—		(3.6	)
Industrial	(6.7	)	(6.3	)

	2009 vs. 2008			2008 vs. 2007


	(In millions)
Distribution volumes	$	1.5		$	(5.1	)
Residential customer rate credit		(17.4	)		—
Conservation surcharge		1.0			(0.1	)
Revenue decoupling		(1.8	)		6.2
Gas cost adjustments		(130.0	)		20.3

Total change in gas revenues from gas system sales		(146.7	)		21.3
Off-system sales		(116.6	)		40.3
Other		(2.4	)		(0.4	)

Total change in gas revenues	$	(265.7	)	$	61.2

		Standard & Poors Rating Group	Moody's Investors Service	Fitch Ratings


Constellation Energy
	Senior Unsecured Debt	BBB-	Baa3	BBB-
	Commercial Paper	A-3	P-3	F3
BGE
	Senior Unsecured Debt	BBB+	Baa2	BBB+
	Commercial Paper	A-2	P-2	F2

	2009 vs. 2008			2008 vs. 2007


	(In millions)
Realization of (lower) higher contract prices on fuel purchases to operate our generating assets in the PJM and New York regions	$	(294	)	$	223
Increase in purchased energy costs due to power purchase agreement with CENG effective November 6, 2009, net of a decrease due to the deconsolidation of CENG		69			—
Decrease in volume of fuel purchased to operate our generating plants		(29	)		—
Increase in volume of output due to lower planned and unplanned outages at our generating plants		22			8
All other		8			3

Total (decrease) increase in Generation fuel and purchased energy expenses	$	(224	)	$	234

	Settlement Term

	2010		2011			2012			2013			2014			2015		Thereafter		Fair Value

	(In millions)
Level 1	$	1.6	$	—		$	—		$	—		$	—		$	—	$	—	$	1.6
Level 2		73.7		636.5			102.1			(18.1	)		(2.9	)		0.1		1.3		792.7
Level 3		58.6		(197.9	)		(140.6	)		(12.8	)		10.4			9.9		2.4		(270.0	)

Total net derivative asset (liability) subject to mark-to-market accounting	$	133.9	$	438.6		$	(38.5	)	$	(30.9	)	$	7.5		$	10.0	$	3.7	$	524.3

	2009		2008		2007


	(In millions)
Actual costs	$	1,781.9	$	1,821.1	$	1,759.2
Deferral under rate stabilization plan		—		—		(287.3	)
Recovery under rate stabilization plans		59.0		59.0		28.5

Electricity purchased for resale expenses	$	1,840.9	$	1,880.1	$	1,500.4

Year ended December 31,	2009			2008		2007


	(In millions)
Financing activities—proceeds from contract and portfolio acquisitions	$	2,263.1		$	—	$	847.8
Investing activities—contract and portfolio acquisitions		(2,153.7	)		—		(474.2	)

Cash flows from contract and portfolio acquisitions	$	109.4		$	—	$	373.6



		(In billions)
Expiration of EDF interim backstop liquidity facility		$	(0.6	)
Credit facility reductions triggered by completion of CENG joint venture (1)			(3.3	)
New credit facilities added			1.4

	Net reduction in credit facilities				$	(2.5	)
	Decrease in letters of credit issued					1.9
	Repayment of cash drawn on facilities					0.9
	Increase in cash					3.2
	Less: cash reserved for tax payments and debt reductions					(1.3	)
	EDF put arrangement, after-tax					1.1

Increase in net available liquidity					$	3.3

For the year ended December 31,		2009		2008


		(In millions)
95% Confidence Level, One-Day Holding Period
	Year end	$	73.0	$	135.6
	Average		92.8		N/A
	High		122.8		N/A
	Low		64.1		N/A

	2010			2011			2012			2013			2014			Thereafter			Total			Fair value at December 31, 2009


	(Dollars in millions)
Long-term debt
Variable-rate debt	$	—		$	—		$	246.9		$	—		$	—		$	403.0		$	649.9		$	649.9
Average interest rate (A)		—	%		—	%		3.16	%		—	%		—	%		1.22	%		1.96	%
Fixed-rate debt	$	56.9		$	81.8		$	676.9		$	466.6		$	90.4		$	2,852.4		$	4,225.0		$	4,433.1
Average interest rate		5.68	%		5.95	%		6.84	%		6.06	%		5.33	%		6.61	%		6.53	%

At December 31,


Rating
	Investment Grade (1)	43	%	52	%
	Non-Investment Grade	2		15
	Not Rated	55		33

At December 31,


Investment Grade Equivalent	88	%	74	%
Non-Investment Grade Equivalent	12		26