Exhibit 99.1

May 31, 2006

The Honorable Thomas V. Mike Miller, Jr.

President, Senate of Maryland

State House, H-107

State Circle

Annapolis, MD 21401-1991

The Honorable Michael E. Busch

Speaker, Maryland House of Delegates

State House, H-101

State Circle

Annapolis, MD 21401-1991

Dear President Miller and Speaker Busch:

In light of the recent debate in Maryland about increases in the cost of electricity, and the concurrent consideration and review by the Maryland Public Service Commission (“PSC”) of the proposed merger between our company and FPL Group, Inc. (“FPL Group”), Constellation Energy Group, Inc. (“Constellation Energy”) and its subsidiary, Baltimore Gas and Electric Company (“BGE”), welcome the opportunity to respond to your questions and requests for information regarding four stated subjects of interest to you and your constituents, as outlined in your letter to us on May 16, 2006.

As you will read below, we are providing information to the extent we are able within certain confidentiality requirements prescribed by the rules for the Maryland electricity market. In this letter, we voluntarily disclose information which we would not ordinarily put into public view because the information is clearly commercially and competitively important to our businesses, including investment costs and asset valuations as well as commercial outcomes of competitive procurement wholesale power auctions. We are mindful, however, of the public’s desire to know certain details and we have therefore gone to considerable lengths to find a process whereby we can provide information that is subject to these confidentiality strictures. Similarly, we view information about the compensation of executive management as important competitive information which would only be disclosed as a result of the merger process in due time and under the rules and regulations of the U.S. Securities and Exchange Commission

(“SEC”). This is information that has been or is going to be shared with certain parties to the PSC merger review proceeding under conventional and appropriate protections of confidentiality, where applicable. Nevertheless, to comply with your request and to clarify and correct any misinformation about executive compensation, we are including information about how the pending merger would affect the compensation of executive officers of Constellation Energy. These are the senior executives who are accountable to the Board of Directors and the shareholders and are responsible for managing the business, setting strategy and making decisions that affect the performance of the corporation.

We will also take this opportunity to address the underlying reasons for the recent rise in local electricity prices. The reason the increase in the electricity portion of BGE customers’ bills will be 72% starting July 1st is not because Maryland’s 1999 electric industry restructuring has failed but rather reflects the current state of the high global energy prices. In fact, during the restructuring and transition to a competitive market, BGE residential customers have already and permanently saved more than $1 billion and a great many of the commercial and industrial business customers have availed themselves of competitive energy offerings that have saved them many hundreds of millions of dollars. The market for wholesale generation supply is highly competitive in the Mid-Atlantic region, and this competition benefits all customers, including residential customers, through either the auction process or access to retail suppliers.

The 72% figure reflects the reality that prices have not increased for residential customers for 13 years because they were frozen in 1999 at 1993 levels, and then were decreased in 2000 by 6.5% and held at that artificially lower level for the six years that will end June 30, 2006. Now, at this juncture when the rate freeze is ending, the overall wholesale market price for power has risen substantially and remains high today – thus the large percentage increase. In terms of the actual cost of the energy component of their bills, BGE customers will be paying rates that are nearly identical to customers of other investor-owned utilities in Maryland that have made the transition away from price freezes, and lower than the rates paid by customers of many utilities in the eastern United States. Furthermore, those rates are a result of a competitive bidding process that yields a true reflection of prices in the wholesale power market in PJM Interconnection, L.L.C. (“PJM”), which is the largest wholesale market in the world and is rigorously overseen by the Federal Energy Regulatory Commission (“FERC”). Wholesale electricity market prices in turn reflect a myriad of factors including of course weather and seasons, fuel inputs – especially coal, natural gas, oil and uranium, all of which have been bid upward by intense global demand for basic energy sources – as well as other inputs such as the cost of high voltage interstate transmission service, the cost of certain reliability functions and reserve capacity, the cost of environmental emission allowances, and very importantly the overall cost of borrowing money for this highly complex and capital intensive industry.

We know that higher energy prices are not welcome news. But the phenomenon of higher energy prices is not unique to Maryland. It is a worldwide issue that cannot be avoided and can actually be exacerbated by local attempts to cap prices or otherwise deny

the reality of how the energy markets work. It is unfortunate that the very substantial economic benefits from restructuring of the Maryland energy market have been obscured by the overall rise in commodity prices.

Constellation Energy and BGE demonstrated our willingness to be constructive during the 2006 General Assembly session when we negotiated with you and your colleagues to offer $600 million over ten years in cash subsidies to BGE customers tied to benefits of our potential merger with FPL Group. At the same time, as you know, we expressed our complete confidence in our legal right to full recovery of these higher energy costs that BGE incurred when it entered into contracts with suppliers to procure the power it needs to serve its customers. We also expressed our complete confidence in the binding legality and fairness of the stranded cost recovery provided for in BGE’s 1999 settlement agreement (“1999 Settlement”),(1) an agreement and process which we recap in our response to your questions about power plant valuations and our subsequent investments in those facilities.

To help the public and policy makers better understand how meaningful the economic contribution from electricity restructuring has been, Constellation Energy recently engaged the economic consulting firm Bates White, L.L.C. (“Bates White”) to perform an empirical market analysis of the actual rates BGE customers have paid over the past six years to the probable rates they would have paid under a regulated market structure. In the study, Bates White concludes that BGE residential customers saved $1.8 billion over the period July 1, 2000 to June 30, 2006, and commercial and industrial customers saved approximately $800 million from their ability to shop for power in a competitive market. A copy of their analysis is attached to this letter.

This letter underscores some of the most important facts about Maryland’s electric industry restructuring, through the enactment of the Customer Choice and Competition Act of 1999 (“1999 Restructuring”), and the relationship between those changes and the current 72% rate increase. We hope this will serve as a counterweight to much of the supposition and conjecture that has been inaccurately represented to the public as fact in the last two months and are confident that an empirical review of the record will show that the 1999 Restructuring was highly beneficial for customers.

With respect to generation supply, the 1999 Restructuring effectively replaced one form of regulation with another as wholesales sales of electricity, such as those resulting from Maryland’s auction process, are subject to the oversight of the FERC. These markets continue to be heavily regulated, but are very competitive, and the overall transition has benefited customers significantly, in spite of the unfortunate reality that electricity prices must be subject to a sudden increase with the expiration of 13 years of frozen prices.

(1) In the Matter of the Baltimore Gas and Electric Company’s Proposed: (A) Stranded Case Quantification Mechanism: (B) Price Protection Mechanism: and (C) Unbundled Rates, Order No. 75757, dated Nov. 10, 1999, Case Nos. 8794, et. al.

We have tried to answer your questions forthrightly while also focusing on some important themes that should receive more attention in the policy debates that have emerged in recent weeks, including:

Competition for electric supply is intense – In Maryland and throughout PJM, the wholesale electricity supply market is highly competitive, and this competition benefits all customers including residential customers.

The 1999 “deal” was fair at the time and its net impact still looks balanced today – With the benefit of hindsight, the 1999 transfer of BGE’s generation to a its affiliates, combined with stranded costs collection and the lowering and freezing of electricity rates for up to six years continues to be a fair deal for consumers.

Constellation Energy will earn reasonable profits on sales to BGE – While a subsidiary of Constellation Energy will indeed be providing a significant amount of power to BGE during the coming year (as it has for the past six years), it won the right to do so by emerging as the low-cost provider in a competitive and highly regulated auction process, and it will generate profits on these sales consistent with the highly competitive market in which it operates. Had Constellation Energy not emerged as the low cost supplier, BGE’s residential customer rates would be higher

BGE’s prices are comparable to other utilities in Maryland and elsewhere -As noted later in this document, relative to other utilities in Maryland, BGE has the lowest weighted discounted average term price for residential customers in the 2006. Granted, the percentage increase in BGE’s average bill was higher than recent percentage increases for the other Maryland utilities. That is because the other utilities increased rates in each of the last 2 years, in both 2004 and 2005, while BGE’s rates were still frozen below 1993 levels in each of those years. As BGE’s rates will soon be unfrozen, its prices are moving up to levels in other parts of the State while remaining below many utilities in the Northeast. Importantly, despite the fact that percentage increases are higher in BGE’s territory, average bills for electricity are approximately at the same level for Delmarva Power and Light Company, Potomac Electric Power Company (“Pepco”) and BGE.

We suggest that consideration of improvements to Maryland’s electricity market should proceed through the formal multi-stakeholder process recently initiated by the PSC in Cases Nos. 9063 and 9064, which should build a good foundation for any future deliberations in next year’s General Assembly about whether any changes are warranted or desirable. We will be active participants in these discussions and will offer constructive proposals to ensure that the benefits of competition persist and that BGE is able to continue providing safe and reliable delivery of gas and electricity at a low cost as it has done for 190 years.

Here, in the order in which they were posed, are the responses to your information requests:

Item (1) - The complete compensation enhancement details (by named recipient and in total) of all officers, employees, consultants, committees and/or agents of Constellation Energy Group, Inc. (“Constellation”) and its affiliates or subsidiaries and Baltimore Gas & Electric Company (“BGE”) that are associated with the proposed and pending merger and FPL Group, Inc. (“FPL”). (1) (1) Including but not limited to: salaries; bonuses; deferred compensation; stock; stock options; termination packages; retirement compensation; pensions; health care and benefit packages; any and all forms of payment reimbursement or otherwise compensation.

Please see Attachment A, “Executive Compensation Enhancement Details, with Tables.”

Item (2) – The currently assessed value of all of the electricity assets (2) (by electricity asset, as appropriate, and in total) owned by Constellation and its affiliates or subsidiaries and which were acquired by, transferred to, or otherwise realigned between Constellation and BGE following the enactment of Maryland’s 1999 Restructuring law and all associated Public Service Commission Orders; (2) Including but not limited to: generating and transmitting facilities; generating and transmitting lines; and substations.

and

Item (3) – A complete listing of all amounts invested annually between 1999 and the present in the above-described assets (including the reason for each investment).

You have asked for the currently assessed value of the electricity assets owned by Constellation Energy that were legally transferred to Constellation Energy from BGE and our subsequent investments in those facilities, all of which are electric power generating stations with certain limited interconnecting equipment associated with the power plants. Effectively no transmission or distribution assets were realigned as a result of the changes in Maryland law and regulation.

We assume that your intention, at least in part, is to also understand what these assets are worth in the sense of their market value, as opposed to any assessment for property tax purposes. As we explain below, to estimate the fair market value of the assets requires some description of how these assets are used in our business and how the value of the assets was determined at the onset of the restructuring transition. Also, we welcome the opportunity to offer some context and explanation of how market values change due to fluctuations in commodity prices, changes in interest rates and the impact of environmental regulation or alterations in the needs of homeland security.

Change In Asset Ownership After 1999 Restructuring and Stranded Cost Recovery

In connection with the 1999 Settlement associated with the move to restructured electricity markets in Maryland, the former BGE assets were transferred to Constellation Energy on July 1, 2000. As part of the settlement process associated with the 1999 Restructuring, Maryland-based utility companies agreed to either selling their generating assets or transferring those assets at a specified value to deregulated affiliates. In the case of three of the Maryland utilities, Pepco decided to sell its assets, and both Allegheny Power and BGE transferred their respective generating assets to non-state jurisdictional affiliates. These asset transfers had the same legal effect as a sale and resulted in the transfer at values, once stranded costs were taken into consideration, that were reflective of market prices for the respective generation facilities at the time of the settlement.

Under “traditional” utility regulation, utilities like BGE were obligated to serve all customers and had to build or buy the assets required to enable them to do so, including generation. In exchange, the utility’s investors, shareholders and bondholders, were promised that the costs of that generation, plus a return on their investment, would be recovered from the utility’s customers, as long as the generation investments were prudent and the facilities were operated prudently. This agreement was often referred to as “the regulatory compact.” Thus, investors built, owned and operated the generation facilities and provided electric service to customers; the price for that service was regulated and determined based upon the cost of our investment, but customers were never provided with any “ownership right” in the generating facilities, although the customers in their status as rate payers bore substantial potential risks of higher prices in the event of construction cost overruns, fuel adjustments, or extended shutdowns of facilities. With implementation of the 1999 Restructuring, the electric companies’ shareholders and bondholders expectation of recovery of their investment and return on that investment was cut short by this change in the industry’s structure. Stranded cost recovery and transition charges were therefore, in essence, a negotiated value to settle BGE’s obligations to its investors in exchange for investors assuming all of the risks and costs of those generating assets; and consequently today, BGE customers no longer bear any of those risks or costs. Of course, BGE continues to be extensively regulated by the PSC with respect to the rates it charges and the services it provides to customers, including, for instance, the provision of delivery service.

For BGE, a fair allocation of the cost of the transition from an approved rate of return to the more competitive model was determined to be $528 million, to be recovered from BGE customers over six years, as agreed to by the parties to the 1999 Settlement, approved by the PSC and confirmed by the courts.(2) The $528 million of stranded costs largely reflects assets whose value at the time of the 1999 Settlement was agreed by all parties to the 1999 Settlement to be less than the book value of those assets.

(2) Mid-Atlantic Power Supply Association v. Public Service Commission of Maryland, et al., 361 Md. 196, 760 A.2d 1087 (2000).

As a result, the BGE plants were transferred to Constellation Energy’s generating company affiliates at an asset value of $2.3 billion which was determined by taking the book value of the plants assets of $2.8 billion less approximately $500 million of stranded costs.

For the generating assets formerly owned by BGE, this “stranded cost” primarily reflected the value of Calvert Cliffs Nuclear Power Plant (“Calvert Cliffs”). At the time of the 1999 Settlement and subsequent asset transfer, nuclear power plants were not highly valued due to low fuel prices for commodities such as natural gas and coal, high fixed operating costs and associated nuclear and fossil plant operating risk. As a result, fossil fuel-fired power plants with much lower fixed-cost structures were considered more valuable than nuclear power plants. As a point of reference, during the period from July 1999 to November 2000, six nuclear power plants were sold at market values ranging from $16/kW to $287/kW. For comparison purposes, at the time of the asset transfer, Calvert Cliffs had a book value of approximately $700/kW, clearly indicating that the market value of Calvert Cliffs at the time of the asset transfer was well below its book value, resulting in the calculation of stranded costs. It is also important to note that the 1999 Settlement and the associated value of the transferred assets was fully litigated in the courts and determined to be valid.

Reallocation of Business Risk From Ratepayers to Shareholders

The transfer of the generating assets also resulted in the transfer of all of the risk associated with operating the power plants and the costs required to maintain and upgrade these plants. Unlike the previous regulated regime, BGE’s customers no longer bear the risk associated with unforeseen outages at these plants which result in Constellation Energy and its shareholders absorbing this risk and the cost of purchasing replacement power in the market. For a point of reference, one need only to go back to the 1989 to 1991 time frame when both units at Calvert Cliffs incurred extended outages resulting in $458 million of replacement energy costs, all but $118 million of which was paid by BGE customers through the regulated fuel rate. If a similar outage occurred in today’s market, the price of replacement energy would exceed $1.5 billion, all of which would be borne by Constellation Energy and its shareholders. Thus, there was a very meaningful transfer of risk that accompanied the transfer of the assets from BGE to Constellation Energy’s generating company affiliates on July 1, 2000.

In addition to the risk transfer, Constellation Energy also assumed all costs and substantial new homeland security requirements, required to maintain and upgrade these plants to meet today’s operating standards as well as to extend the lives of these assets. We must recover these costs through the market rather than through rates that are administratively determined by the PSC. Since the asset transfer on July 2000, Constellation Energy has invested over $900 million in these generating facilities as indicated in the following table:

Constellation Energy Capital Expenditures on Power Plants

Formerly Owned by BGE, 7/1/2000 to 3/31/2006

Year	Investment ($ millions)
2000, 2nd half	$	98
2001	227
2002	230
2003	134
2004	92
2005	82
2006, 1st Quarter	40

Total Capital Investments	$	903

Major Capital Projects Undertaken by Constellation Energy on Power Plants Formerly Owned by BGE, 7/1/2000 to 3/31/2006

Project	Investment ($ millions)
Fossil Plants
Pollution Control Equipment at Brandon Shores, Keystone, Wagner	$	195
Efficiency and reliability upgrades	60
Wagner precipitator	19
Over 30 projects under $5 million each*	130
Total fossil investments	$	404

Calvert Cliffs
Steam generator replacement	$	206
Reactor vessel head replacement	74
Low-pressure turbine rotors	56
Instrumentation and control	29
Replacement of main transformer	15
Over 40 projects under $5 million each	119
Total investments in Calvert Cliffs	$	500

Total Capital Investments	$	903

These plants are large complicated pieces of machinery which require considerable expertise and investment to keep operating safely and reliably. For instance, since the asset transfer, Constellation Energy has invested significant capital dollars in Calvert Cliffs to maintain the safe, reliable operation of the plant as well as to extend its operating life. This includes, as shown on the table, replacing the steam generators at both units, as well as replacement of the reactor vessel head on Unit 1 (Unit 2 reactor vessel head replacement is planned for next year), and numerous security upgrades to address security concerns following the tragic events of September 11, 2001.

The required capital investments are not limited to Calvert Cliffs. As illustrated above we have also invested considerable capital to maintain safe, reliable operations at our fossil plants as well as meet the increasingly stringent environmental standards for our coal plants. All of these costs are borne by Constellation Energy and its shareholders with no approved and allowed return such as existed when these plants were regulated and earned a return on and of the plant investment, plus recovery of all prudently incurred costs of operating the plants.

To more fully gauge the relative benefit to Constellation Energy and its Maryland customers of the 1999 Settlement, you should consider two issues separately: (1) Actual results to date (how the full bargain, including transfer value, stranded cost collection, and up to six years of fixed frozen rates, has performed for Constellation Energy and our customers); and (2) Potential future results (how the appraised future value of the plants compares to their value in 1999 plus subsequent capital improvements and in consideration of appropriate capital costs).

Actual Results

As to actual results, since 2002 Constellation Energy has separately reported results in its disclosed financials for a line of business called “Mid-Atlantic Fleet.” Included in this business line have been our Maryland power plants, sales to BGE and associated stranded cost collections, and sales to other utilities, as well as other associated sales, fuel purchases and price hedges. Based on the annual net cash flows from these assets (earnings, less capital expenditures and cash taxes) for the past six years, on the $2.3 billion investment and the resulting estimate of annual basis at the time of the 2000 transfer, our average cash return on our total invested capital return has been approximately 6% (including the impact of operating cash flow and capital expenditures). This return is well below BGE’s weighted average cost of capital (of about 8.5%) and even further below an appropriate cost of capital for merchant power plants such as those in the remainder of our fleet of roughly 10%. We estimate the impact of under-earning our cost of capital over the period cost the Company over $0.5 billion which was fully borne by our investors and shareholders.

From the standpoint of our customers, we believe the 1999 Settlement (again including the asset transfer price, stranded cost collection, and rate reduction) has been a tremendous success and rate reductions have resulted in tremendous savings. To estimate actual results for consumers, as previously mentioned, we retained the economic consulting firm Bates White to project the prices that BGE’s customers would have paid had the traditional cost of service model been left in place over the six year period the (Bates White’s analysis is attached). Bates White estimates that across all customer classes, the savings were $2.6 billion.

Potential Future Results

Potential future results are naturally a bit harder to determine (i.e., we know what has actually happened in the past, but we can only project the future with significant uncertainty). In an attempt to provide an assessment of potential future benefits, we turn

to the asset appraisal that we are required to perform as part of our proposed merger with FPL Group, which will be used to properly establish the new balance sheet of the combined company. Given its impact on our financial statements, this appraisal must be performed with very substantial diligence and is subject to review by the SEC. In order to perform this appraisal we have enlisted outside experts, we will require the review of our and FPL Group’s outside auditors, and we this information will ultimately be included as part of the overall financial information submitted to the SEC as part of our Form S-4 filing in connection with the proposed merger. Our appraised value of these power plants as of March 2006 is $4.3 billion. This compares to an appraised value embedded in the 1999 Settlement of $2.3 billion (that is, a book value of $2.8 billion less an approved stranded cost collection of $0.5 billion). We have subsequently invested an additional $0.9 billion, for a new investment basis of $3.2 billion. Over the six year interval since 1999, this represents a fairly modest 5.3% annual rate of appreciation on our investment basis. To put this annual rate of increase in context, it is important to consider several factors:

• This current appraised value of $4.3 billion value is inherently variable and risky because of the volatile nature of the commodity markets and the inherent operating risk associated with operating base load nuclear and fossil generation and we have no means to capture this value today without selling our plants which we have no intention of doing. A sale would also entail a considerable payment of taxes, which would lower the overall value calculation by possibly more than $1 billion. To illustrate, the potential for this value increase to be a temporary one, if we were to have performed a similar appraisal late in the summer of 2005 (before the supply disruptions caused by hurricanes Rita and Katrina, as well as global energy supply disruptions), our plants appraised value would have been lower by roughly $1.0 billion to $1.5 billion (due to significantly lower future energy prices). Therefore, less than a year ago and before these events, our plants would have been worth $2.8 to $3.3 billion as compared to our investment basis of $3.2 billion, implying an annual appreciation since these assets were transferred in July 2000 ranging from a low of negative 2.7% to less than 1.0%. Given that this sudden increase in the appraised value was tied to a few events, we think it is unrealistic to consider it a permanent increase in value.

• We have borne significant risk and the associated capital cost over the period since the assets were transferred on July 1, 2000, and we have earned returns since then well below our cost of capital. Attempting to encourage or compel companies permanently to earn less than their cost of capital would be unsustainable public policy. Maryland consumers have clearly been the beneficiary of the fact that Constellation Energy entered into the 1999 Settlement, approved by the PSC and confirmed by the Courts through which the transferred assets earned less than their cost of capital over the last six years.

• The analysis by Bates White concludes that Maryland consumers have saved $2.6 billion in the last six years over what they would have paid for electricity had the 1999 Settlement not occurred (in which case Constellation Energy would have had

the opportunity to earn its full cost of capital through the traditional ratemaking process).

To conclude, Constellation Energy operates a highly capital intensive and volatile business without the regulated safety net that its shareholders once enjoyed. We succeed in this highly competitive environment by reliably providing energy to our customers at the lowest possible cost. While we earned a sub-par return on invested capital in the transferred power plants relative to the risk shareholders assumed over the last six years, to the direct benefit of Maryland consumers, we, of course, willingly entered into the 1999 Settlement. Despite the fact that absent selling the plants, which we have no intention of doing, there is significant risk to ever capturing the increase in the value of our plants that occurred over the last nine months, we continue to believe that the 1999 Settlement provided a reasonable balancing of the interests of customers, Constellation Energy and BGE.

Item (4) - A complete list of the names of the bid winners and data associated with the bids that resulted from the December 5, 2005 and the January 3 and February 21, 2006 Maryland wholesale auctions (by tranche date and in total).(3) 3Including but not limited to: data illustrating the various amounts to be supplied as percentages of BGE’s aggregate load need; data showing the various suppliers’ production cost per MWh and BGE’s purchase price per MWh for the described power.

As you are probably aware, our ability to respond to your request is limited by confidentiality restrictions. Confidentiality restrictions contained in PSC Orders and agreements associated with the Maryland wholesale auction process (the “Auction Process”) restrict the dissemination of information concerning individual bidders that participate in the auctions.(3) Consequently, we have limited ability to fully respond to your request for information at this time. In addition, BGE has no information related to its bid winners’ cost of supply. Confidentiality of supplier information is a key component of the Auction Process and is relied upon by participating suppliers because it limits the release of commercially sensitive competitive information. Suppliers need these assurances because the disclosure of the specifics of their obligations may interfere with their ability to procure energy needed to serve those obligations in a cost effective manner and may increase the cost of serving those obligations over time. Increased supplier costs would result in higher costs to the utility that would, in turn, result in higher costs to the Maryland consumer.(4) As such, the integrity of the auction rules and processes is vital to their continued success.

(3) Confidentiality of the Maryland Auction Process is required by the terms of the settlement approved by the PSC in Order No. 78710 which states that the handling of confidential information relating to the auction process by the utilities and bidders would be governed by the confidentiality agreements that were approved with the settlement.

(4) Permitting the release of detailed information regarding the winning bidders could increase the cost of serving the utilities because other market participants would become aware of the fact that the suppliers had already sold the energy that they are attempting to procure. This could have the consequence of causing wholesale suppliers to possibly raise their estimate of the costs they will incur to manage risks associated with their obligations, thus raising bid prices, which in turn will raise the prices paid by customers. The possibility of such disclosure may also impact the willingness of bidders to participate in future auctions.

Overview of our response

As to your specific request, we received a copy of the letter to you dated May 23, 2006 from the PSC and understand that that the information you requested will be provided to you by the PSC under certain conditions they describe. What we can provide you with at this time is the context for the rate increase that will be experienced by BGE’s residential customers beginning in July 2006, as well as pertinent data regarding the commercial impacts for Constellation Energy.

Potential wholesale suppliers in BGE’s residential load auctions participated in a highly competitive, transparent process where contracts were awarded on the basis of the lowest price. At the heart of the matter is that the rates at which BGE procured power in the recent auctions were a function of prices experienced by suppliers in the markets for the energy products needed to serve the load obligations. Suppliers are free to determine how they will procure the energy products necessary to perform their obligations to the utilities. They may purchase the power in the spot market on an as-needed basis; they may purchase it bilaterally from various counterparties in the wholesale market for various terms ranging from a day to a year or longer; or they may have access to generation that can be utilized to provide the needed power supply. In addition, winning bidders may manage their risk through various financial instruments. Procuring energy products needed to serve the utilities would typically occur around the time of the relevant auction and may be continuously refined and revised over the length of the contractual obligation.

To illustrate the point that suppliers’ cost to serve is the cost in the market at the time of the auction, we have provided you with information regarding the BGE residential award for the period from July 2006 through May 2007 to BGE’s affiliate, Constellation Energy Commodities Group, Inc. (“CCG”). As you will see, the amount of available load awarded to CCG and CCG’s expected margin associated with that load in this part of the BGE auction is consistent with CCG’s experience in other auctions across its national competitive wholesale supply business. We have also provided you with market context for the prices that BGE was offered in the auctions, as well as a comparison of BGE residential rates to the residential rates of other utility customers for the same period. Finally, we have provided context for the 72% rate increase that will be experienced by BGE residential customers beginning in July 2006. The rate increase is a function of (i) the market prices in effect at the time of the auction and (ii) the fact that BGE customers have experienced frozen rates since June 30, 1999, and are now being brought to market rates. Those rates were the lowest available rates in the market as a consequence of the competitive auction process.

Background on the Maryland Auction Process

The Auction Process in Maryland is designed to generate competitive offers in a transparent and fair auction. BGE and the other major Maryland utilities procure the

power necessary to supply standard offer service (“SOS”) obligations in accordance with the procedures approved by the PSC in a series of orders and regulations issued by the PSC beginning in 2003.(5)

At the heart of the rules is that the lowest prices offered by wholesale suppliers are accepted, and that the procuring utility has no discretion as to the selection of its suppliers. In addition, the process approved by the PSC includes independent oversight by a third party consultant(6) and also provides for the Office of People’s Counsel to monitor the bidding. During the most recent auctions, representatives of both were in the room as all the bids were received and processed, and checked every step of the process. Through this Request for Proposals (“RFP”) process, the lowest price bids were selected by BGE, contracts were entered into with the winning suppliers, and the awards were submitted to the PSC for review and approval. The participating utilities have no discretion in decisions related to awards, and the selection of winning wholesale supplier bids is based exclusively on price.

For Wholesale Suppliers Production Costs Are The Same As Market Prices

In competitive wholesale supply auctions, the supplier’s cost to serve is the cost in the market around the time of the auction to acquire those energy products necessary to manage its obligations. Through its subsidiaries, Constellation Energy is the largest competitive supplier of electricity to utilities and end-users in North America. In this aspect of its business, Constellation Energy seeks to reliably deliver power at the lowest costs to utilities and end-users by managing a portfolio of load commitments and supply resources. Constellation Energy developed a successful competitive supply business because it has been able to provide power to its customers at the lowest possible cost due to the scale of its portfolio and its expertise in managing risks associated with that business.

Our business is very much built on the concept of “forward hedging” that involves securing power (and making fuel purchases) long before actual delivery (or use) of each product. We typically commit to provide power to utilities and other wholesale end-users for periods of one to three years. This practice adds to the predictability of our earnings and insulates us from swings in commodity prices. It ensures that we are not significantly harmed by potential market downturns, but also limits our ability to take

(5) These rules are primarily the result of two orders, issued by the PSC in 2003, that set forth the obligation of BGE, as well as other Maryland utilities, to continue to provide SOS to customers and also established the process by which the purchase of power to meet its obligation would occur. In PSC Order No. 78400, issued April 29, 2003 the Commission approved a settlement that extended the utilities obligation to provide SOS service and established the general framework pursuant to which the utilities would purchase power and recover their costs. In PSC Order No. 78710, issued September 30, 2003, the Commission approved a second settlement that set forth the specific auction process and associated documents, including standardized bid plans, power purchase agreements and confidentiality agreements. The bids are broken down into small blocks, and offered in three different rounds (called “tranches”) spread over several months, so as to encourage small as well as large suppliers to bid, and to spread the prices over time. These procedures ensured a standardized approach to power procurement for all four investor-owned electric utilities in the state.

(6) To date, Boston Pacific Company, Inc. has been utilized by the Commission to provide oversight to the auction process.

advantage of upturns in commodity prices such as the one experienced in the past nine months following the hurricanes.

Because we do not want our operating results to be subject to the potential volatility of commodity markets, for the last several years we have tended to have close to 100% of the expected output of our plants committed for one full year, 80% to 90% committed two years forward and 70% to 80% committed three years forward. We also maintain a balance between our contractual sales obligations and our purchases of power to meet those obligations. Therefore, when CCG enters into significant obligations such as the SOS load in Maryland or the Basic Generation Service (“BGS”) load in New Jersey, CCG must also enter into transactions in the market around the time of the auctions to manage the near-term price and other risks associated with such obligations. Effectively, a substantial amount of the price risk associated with our generating assets is always forward hedged on an economic basis, we are selling to utilities and procuring supply at prices that reflect the prevailing market price at the time of the sale and not based on the production cost of any generation units. Consequently, the prices that CCG and other bidders in these auctions are able to offer to the utilities are inextricably linked to the price of energy and related energy products at the time of the auction.

To give you some perspective on how this business works, in 2005 Constellation Energy had contractual obligations to supply approximately 175 million MWh of full requirements service throughout North America, enough electricity to supply approximately 14.5 million average U.S. households. Against its obligations to serve 175 million MWh of electricity to utilities and end-users, Constellation Energy’s uncommitted generation resources totaled only about 40 million MWh in the same period. Constellation Energy acquired the remaining 135 million MWh necessary to manage its obligations from the wholesale market, managing a large portfolio of both contractual and physical resources to do so.

Results for Constellation Energy From 2006 Maryland Wholesale Auctions

In order to illustrate that CCG’s cost to supply its obligations in connection with the recent Maryland auctions was a function of market prices in effect at the time, we have received permission from the PSC to disclose certain information relating to CCG’s residential award from BGE for the period from July 2006 through May 2007.(7) In the BGE residential auctions, CCG was awarded approximately 9.6 million MWh of BGE residential load obligations (approximately 70% of the load awarded by BGE for that period) at an weighted average contract price of $101.90 per MWh for the term July 1, 2006 through May 31, 2007. Entering the auction season in the Mid-Atlantic region, CCG had resources available for the term June 1, 2006 through May 31, 2007 that were equivalent to 7% of CCG’s total awarded load in all of the Mid-Atlantic auctions. Against this forward hedged position, CCG was required to acquire energy products associated with 8.9 million MWh, or 93% of the power needed to serve its BGE residential load obligations in the market at prevailing market rates. Given our

(7) In the Matter of the Commission’s Inquiry Into the Competitive Selection of Electricity Suppliers Standard Offer Service, Letter Order dated May 31, 2006, Case No. 8908.

above-mentioned forward hedging approach, the marginal cost of generation at our owned power plants is not relevant to the competitiveness of prices offered in the recent Maryland auctions because CCG acquired almost all of the energy products necessary to manage those obligations at prevailing market rates. CCG’s expected margin for the BGE residential load for this period was $3.17 per MWh, or 3.1% of the average contract price on a weighted average basis. CCG’s participation in the recent Maryland auctions enhanced the competitiveness of the prices that were offered resulting in the lowest possible rates to BGE consumers.

Results In Line With Other Auctions

The results in the recent BGE residential auctions were typical of other auction results in CCG’s national load business. Utilities in the Northeast tend to procure power on a seasonal basis, with the bulk of procurements happening between September and March. In the last two procurement cycles (September 2004 to the present), CCG participated in 162 auctions through which utilities in the Mid-Atlantic and New England procured power for residential or commercial rate customers (by auction we mean utility/rate class/time period combination). Our results in these 162 auctions were very consistent in those we just experienced in the recent BGE procurement for residential customers for the 2006/2007 SOS year. For instance, over this time period, we participated in 52 auctions in which BGE or Pepco procured power. In 16 of these we have been awarded 70% or more of the load (31% frequency), and our expected margin on all our wins was 3.3% of average contract price (% margins expressed as simple averages unless otherwise noted). Over the same time period in the rest of the Mid-Atlantic and New England, we participated in 110 such auctions, and were awarded 70% or more of the load 32 times (29% frequency), with an expected margin on all wins of 3.3% of average contract price. We own no generation in New England.

As you can see, the fact that we were awarded 70% of the load in the recent BGE auction with an expected margin of 3.1% of average contract price on a weighted average basis is quite typical for us when compared to the results of BGE and Pepco and the results for the rest of the Mid-Atlantic and New England. In 162 total auctions in the last two procurement seasons throughout PJM and New England (a total region representing about 16% of the total US power demand), we have been awarded 70% or more of total load in 30% of all auctions and our average expected margin on all awards was 3.3% of average contract price. Furthermore, you see no significant difference in our success rate or our margin percentage in any region, regardless of our generating plant ownership position in the region. CCG’s success at such auctions is a result of its ability to deliver a lower cost product through its expertise in managing the attendant costs and risks associated with providing full requirements service such as that provided to BGE and by leveraging the national scale of our business, which enables us to pass on scale economies in power procurement and risk management to our customers. Our business is built on a simple objective: reliably delivering energy products to our utility and end-use customers at the lowest possible price – we succeed by being the low cost provider.

BGE procured load at competitive rates in the recent auctions

Relevant information concerning the overall results of the recent Maryland Auctions has been made available to the public. The PSC Staff Report (“Staff Report”) issued March 7, 2006 regarding the December 2005 and January and February 2006 auctions reported that that there were “sixteen (16) eligible bidders in this process of which thirteen (13) suppliers actually submitted bids and ten (10) suppliers won some portion of the load offered this year. Starting in June 2006, twelve (12) different suppliers will be serving SOS customers.”(8) The Staff Report also indicated that the residential rates experienced by each of Delmarva Power & Light (“DP&L”), Pepco and BGE were consistent with one another.

These results are confirmed in a recently release report by the independent third party consultant who oversaw the Maryland auction process. In the Final Report of the Technical Consultant on the 2005-2006 RFPs for Standard Offer Service, dated May 25, 2006, Boston Pacific Company, Inc. reviewed the bidding process in Maryland and the ensuing prices. It found, among other things, that: (1) the RFPs were run properly and securely; (2) winning bidders were selected on the basis of low price only; (3) the number of winning bidders in Maryland is “comparable to neighboring jurisdictions”; (4) there was more than enough conforming bids, on average, to cover all bid blocks; (5) relative to the other utilities in Maryland, BGE has the lowest weighted discounted average term price for residential customers in the 2006-2007 auction.(9)

BGE procured power at rates that reflected market conditions at the time of the auctions

The bid prices in the Maryland Auction Process reflect market conditions at the time of the auctions. The Staff Report found that “[t]he bid prices reflected general economic conditions including high and rising prices for the fuels used to produce electricity as well as increased congestion into parts of Maryland. The rising price of fuels reflects a worldwide increase in demand and tightening supply for energy resources, and unfortunately the effects of Hurricanes Katrina and Rita magnified the increase.”(10)

BGE’s experience was similar to the experience of neighboring utilities. The New Jersey Board of Public Utilities announced the results of that state’s fifth electric auction for BGS and concluded that “[t]he results of this year’s auction reflect increasing costs in our world energy markets, especially in natural gas. These cost increases are driven by growing international energy demand and supply constraints that were exacerbated by the impacts of Hurricanes Katrina and Rita. Despite this expensive market, through our unique auction process New Jersey’s rates are the best possible in

(8) In the Matter of the Commission’s Inquiry Into the Competitive Selection of Electric Supplier/Standard Offer Service,. The Commission Staff’s Report/Observations on the Standard Offer Service Bidding Process and Results, dated Mar.7, 2006, Case No. 8908, at p. 3 (“Staff Report”).

(9) Boston Pacific Co., Inc., Final Report of the Technical Consultant on the 2005-2006 RFP, for Standard Offer Service, dated May 25, 2006, available at www.psc.state.md.us.

(10) Id.

light of current market conditions and compare favorably to some states such as New York, Massachusetts, Connecticut and Delaware.”(11)

BGE’s results in the recent auctions are consistent with results experienced in other jurisdictions

The results of the recent Maryland auctions are also consistent with prevailing rates in other jurisdictions. For instance, the typical residential monthly electric bill (830 kWh) for a BGE customer as of July 2006 is estimated to be $115; this can be compared to:

• Pepco (MD) at $113;

• SMECO at $105;

• PSE&G (NJ) $119

• Delmarva (DE) at $123;

• PECO (PA) at $124;

• Connecticut Light and Power (CT) at $146

• Boston Edison (MA) at $173.

Why are BGE customers experiencing a 72% rate increase?

Clearly, the recent Maryland auctions produced competitive, market based energy prices for the Maryland utilities. CCG’s participation in the auctions served to enhance the competitiveness of the process where the lowest prices win. The only significant difference between BGE and the other utilities in Maryland is the percentage increase in the rates that BGE must collect from its customers. The 72% increase associated with the rates that BGE must collect from its residential customers, in comparison with this year’s lesser increases for Pepco and DP&L,(12) is a result of the fact that Pepco and DP&L customers had already experienced significant prior price increases in 2004 and 2005 due to moving away from frozen rates 2 years earlier than the BGE customers. BGE customers, on the other hand, had not experienced an increase in the base electric rates since 1993 and experienced frozen rates since June 30, 1999 as a result of the 1999 Settlement. Despite the fact that the percentage increases are higher in BGE’s territory, average bills for electricity are approximately at the same level for DP&L, Pepco and BGE.

###

In conclusion, we appreciate and share the concern that everyone feels about the challenge of rising energy costs. Constellation Energy and BGE have tried to explain the complex nature of the electric power industry and the underlying forces that result in price fluctuations. We hope you will find this context from our answers helpful. We believe this context shows that competition in our industry is robust and is providing great benefits to consumers.

(11) New Jersey Board of Public Utility’s Press Release, NJ’s 5th Auction Again Provides Best Possible Rates dated Feb. 9, 2006.

(12) Staff Report at pp.4-5.

ATTACHMENT A

Request:

The complete compensation enhancement details (by named recipient and in total) of all officers, employees, consultants, committees and/or agents of Constellation Energy Group, Inc (“Constellation”) and its affiliates or subsidiaries and Baltimore Gas & Electric Company (“BGE”) that are associated with the proposed and pending merger with FPL Group, Inc. (“FPL”). FN: Including but not limited to: salaries; bonuses; deferred compensation; stock; stock options; termination packages; retirement compensation; pensions; health care and benefit packages; any and all forms of payment, reimbursement or otherwise compensation.

Response:

In the discussion below, we have discussed each material plan or arrangement that could result in a significant enhancement of compensation or that could otherwise be significantly affected, as a result of the proposed merger with FPL Group. In response to your question, we have provided specific information relating to each of Constellation’s executive officers by name. With respect to employees who are not executive officers, Constellation believes that such information, which is not required to be submitted in connection with any current public disclosure requirements, would reveal information regarding individual non-executive employees that is confidential, private to the individual and inappropriate to disclose in this letter.

It should be noted that to the extent any compensation is enhanced as a result of the proposed merger with FPL Group the costs of that enhancement will not go into any account that finds its way to BGE ratepayers.

Since compensation, including the elements that are discussed below, is earned and vests over time and some of it is dependent on the value of Constellation stock, the actual amount that we indicate will be received by an executive officer is dependent on the date we assume for merger closing and the stock price. In our responses, we have assumed that the merger would be completed on December 31, 2006, and that Constellation’s stock price is $52 per share. These are only assumptions, as the merger could be completed on a different date and the stock price could be different as of the completion date of the merger.

As background, Constellation has designed its compensation policies to encourage executives to manage Constellation in the long-term best interests of its shareholders by enabling it to compete for, attract and retain highly motivated employees with outstanding skills and who are best suited to drive its success over the long term and by aligning their interests with those of the shareholders. Constellation uses benchmarking data from a number of sources to design compensation policies and packages and also uses the services of outside executive compensation consultants as advisors in the area of executive compensation and benefits. Constellation’s compensation philosophy is that

executive base salaries should be linked to the median level of base salaries in the relevant labor market. Incentive compensation, in the form of annual bonuses and long-term incentive compensation such as stock options, is designed to reward executives based on performance, and is intended to bring total compensation to the 75th percentile for superior personal and company performance.

It is also important to note that Constellation and BGE compete for employees from two largely different labor pools. The business model of Constellation, and its position as the leading power trader in the country, requires that we attract and retain the best talent possible to compete against the large Wall Street investment banks. In that regard, Constellation has added nearly 1,000 jobs in Maryland since the inception of the power trading business. In addition, the costs associated with the employees in Constellation’s competitive energy businesses have no impact on the rates paid by BGE ratepayers. In contrast, BGE draws more of its employees from traditional utility labor pools, with a corresponding different compensation level that relates to the different labor market.

The following information first outlines enhancements to ongoing compensation arrangements as requested. For the avoidance of doubt, we also describe arrangements for employees terminated following the merger and the terms under which pre-existing compensation arrangements will be satisfied at the time of the merger. A separate section is provided on Mr. Shattuck’s employment agreement.

I. ENHANCEMENTS TO ON-GOING COMPENSATION ARRANGMENTS

The only arrangements that we believe constitute enhancements to on-going compensation that were put in place as a result of the merger are retention awards to employees who are not executive officers. These awards are designed to retain key employees of Constellation who might otherwise seek alternative employment due to the perceived uncertainty of their jobs after a merger with FPL Group, and thus to help ensure the ongoing stability of Constellation’s business. As of the date of this letter, the aggregate amount of retention awards that has been granted to 220 employees is approximately $15.0 million, none of which has been awarded to any executive officer of Constellation and none of which will be charged or allocated to BGE.

II. TERMINATION ARRANGEMENTS

It is general business practice to provide that if an executive is terminated following a corporate transaction such as a merger, he or she is assured of certain benefits. This is not an enhancement to ongoing compensation, but rather an assurance of what the executive will receive if terminated after completion of a major transaction for which they have likely provided significant efforts. These predetermined arrangements for termination following a merger are very commonplace in corporate America, in order to ensure that executives will always work in the best interests of the shareholders even if the executive knows that he or she may lose his or her job following a transaction such as a merger.

As previously disclosed to the Public Service Commission, each of the following eight executive officers of Constellation is party to a change in control severance agreement with Constellation, copies of which have been provided to the Public Service Commission (in addition, copies of the agreements for Messrs. Shattuck and Brooks and Ms. Smith have been filed with the SEC and described in our recently filed Form 10K/A):

Thomas Brady

Thomas Brooks

John Collins

Mayo Shattuck

Follin Smith

Marc Ugol

Michael Wallace

Irving Yoskowitz

The remaining five Constellation executive officers are not parties to any similar agreement with Constellation.

The change in control severance agreements, which largely follow a format adopted by Constellation in 1995, provide that certain benefits are payable to an executive officer only if both of the following conditions are met:

• if his or her employment is terminated by Constellation without “cause” or by the executive officer for “good reason” (referred to herein as a “qualifying termination”) and

• such termination is within two years after a change in control

Since the proposed merger with FPL Group would be considered a change in control under the agreements, the benefits would be payable only if there is a qualifying termination of the executive officer’s employment within the two year period after the completion of the merger. In general, if an executive officer’s employment is terminated following a merger, he or she receives compensation and benefits essentially as if he or she had worked for an additional two to three years, depending on the specific agreement.

We again feel we should point out that if any of the payments outlined below are made, they will not be charged or allocated to BGE.

A. Potential Cash Severance Payments to Executive Officers – Salary and Bonus

Pursuant to the change in control severance agreements, in the event of a qualifying termination of an executive’s employment, an executive officer who is party to such an agreement will receive two or three years of salary and bonus in the form of a cash payment, depending on the specific agreement. Mr. Shattuck, in connection with entering into the employment agreement discussed below, waived the payment of any

cash severance. Ms. Smith has already been designated for a position with Constellation effective as of completion of the merger and hence is currently not expected to receive any cash severance upon completion of the merger. Other executive officers will be designated to positions with Constellation effective as of completion of the merger that would result in such executive officers not receiving cash severance upon completion of the merger.

However, in the interests of full disclosure, the table below sets forth, for each executive officer who is party to a change in control severance agreement (other than Mr. Shattuck, who has agreed to waive any cash severance payment), the cash severance payment the executive officer would receive based upon current base salary and bonus amounts if he or she were terminated on December 31, 2006:

Executive Officer	Number of years of base salary and bonus		Potential cash severance payment
			($’s in 000’s)
Brady, Thomas	3		2,760
Brooks, Thomas	2, subject to cap		5,000
Collins, John	2		1,167
Shattuck, Mayo	—	(a)	—	(a)
Smith, Follin	3		6,562	(b)
Ugol, Marc	3		2,175
Wallace, Michael	3		5,737
Yoskowitz, Irving	3		4,095

(a) In connection with the execution of his employment agreement, Mr. Shattuck has waived any payment of cash severance under his change in control severance agreement.

(b) Ms. Smith has been designated to a position effective upon completion of the merger and hence is not expected to receive any cash severance upon completion of the merger.

B. Potential Enhanced Retirement Benefits for Executive Officers

Consistent with the concept that certain executive officers should be treated, in the event he or she is terminated, as if they had worked an additional two or three years, we define the treatment of retirement benefits if an executive is terminated in the change in control severance agreements (other than for Mr. Brooks, who has no enhanced benefits in this regard) and in Mr. Shattuck’s employment agreement. If there is a qualifying termination of the executive officer’s employment within two years after a change in control, the executive officer is entitled to a cash payment of supplemental retirement benefits. For Mr. Shattuck, he will be entitled to benefits under the senior executive supplemental plan, pursuant to the terms of his employment agreement and the senior executive supplemental plan, only if he is demoted from his position as Chairman or his employment is terminated without cause. Otherwise, he will not vest in his benefits under the senior executive supplemental plan until November 2011, and would forfeit the entire amount if he voluntarily terminated his employment prior to that date.

As noted above, Ms. Smith has already been designated for a position after the merger that should not constitute a qualifying termination of her employment, and other executive officers will be designated for positions that would make it unlikely that they would be entitled to any enhanced supplemental retirement benefits as a result of the merger.

However, again, in the interests of full disclosure, the table below sets forth the estimated value of accelerated and enhanced supplemental retirement benefits (excluding any amounts that are already vested) that would be payable to each executive officer who is party to a change in control severance agreement, if there was a qualifying termination of his or her employment on December 31, 2006:

Executive Officers	Acceleration of amounts executive would have otherwise received if not terminated (A)		Enhancement if terminated (B)		Total potential value if terminated (A + B)
	($’s in 000’s)		($’s in 000’s)		($’s in 000’s)
Brady, Thomas	—		1,318		1,318
Brooks, Thomas	—		—		—
Collins, John	—		235		235
Shattuck, Mayo	—		4,267		4,267
Smith, Follin	3,302	(a)	3,863	(a)	7,165	(a)
Ugol, Marc	267		314		581
Wallace, Michael	—		6,399		6,399
Yoskowitz, Irving	211		727		938

(a) Ms. Smith has been designated to a position effective upon completion of the merger and hence is not expected to receive any enhanced supplemental retirement benefits upon completion of the merger.

C. Treatment of Annual Incentive Bonus in Year of Termination

Executives are also entitled to a payment of a pro-rata amount of their annual bonuses in the event they are terminated within two years after a change in control. You should know that all Constellation employees are eligible for an annual bonus based upon achievement of performance goals. Approximately 150 of these employees are eligible for an annual bonus under the terms of Constellation’s Annual Incentive Plan (which has been publicly filed with the SEC and provided to the Public Service Commission and which was not modified in connection with the proposed merger with FPL Group). This Plan provides that if an employee is terminated within two years after a change in control (the proposed merger with FPL Group would be considered a change in control), the employee would be entitled to a payment of his or her target award for the year of termination, assuming maximum performance for the part of the year actually worked by the employee. Thus, the bonus is payable early to an employee only if his or her employment is actually terminated, and the amount payable is enhanced to ensure a

maximum payout without respect to Company performance only if the employee is actually terminated.

In the interests of full disclosure the table below sets forth, for each executive officer, the entire full-year bonus amount the executive would be entitled to receive if the merger with FPL Group is completed on December 31, 2006 and the employment of such executive officer is immediately terminated:

Executive Officer		Pro-rata bonus for year of termination (assuming 12.31.06 termination)
		($’s in 000’s)
Allen, Paul		357
Brady, Thomas		510
Brooks, Thomas		—
Collins, John		352
Dawson, Felix		—
DeFontes, Kenneth		525
Perlman, Beth		855
Persky, George		—
Shattuck, Mayo		—
Smith, Follin		1,725
Ugol, Marc		450
Wallace, Michael		1,575
Yoskowitz, Irving		1,068

You should note that bonuses are paid for calendar year performance, so as of January 1st the pro rata amount would be zero, while on June 30th it would be 50%, and on December 31st it would be 100%. Thus, the payments set forth above are the highest amounts that could be paid to each executive officer in the event of a termination of employment within two years after a change in control.

D. Other potential benefits

In the event of a qualifying termination, the executives officers (other than Mr. Brooks) who are parties to change in control severance agreements will receive two or three years, depending upon the executive officer’s agreement, of continued heath and life insurance benefits, which is consistent with the concept that the executive officer should be treated, in the event he or she is terminated, as if he or she had worked an additional two or three years, depending upon the terms of the executive officer’s agreement. Constellation estimates the cost of these benefits to be between $29,000 and $46,000 for each executive officer.

In connection with the foregoing payments, in the event taxes are payable under Section 4999 of the Internal Revenue Code (commonly referred to as parachute excise taxes), similar to many other companies, Constellation would pay an amount calculated so that the executive officer is in the same position as if no such excise taxes were imposed over and above the normal income taxes which the executive officer must pay.

III. TREATMENT OF OUTSTANDING AWARDS UNDER CONSTELLATION COMPENSATION PLANS

It is generally accepted practice for corporate compensation plans to address the treatment of outstanding but as yet unpaid awards at the time of a transaction such as the proposed merger with FPL Group. In this way, the “old” company’s commitments are fulfilled and the “new” company enters into new arrangements on a forward-looking basis. Constellation’s compensation plans provide that the merger with FPL Group would be a change in control that would result in the vesting and payment of certain outstanding awards, as outlined below.

A. Treatment of Outstanding Long-Term Incentive Awards

The proposed merger with FPL Group would be a change in control under Constellation’s plans which govern items such as stock options, restricted stock and performance units. These plans date back to 1995, 1998 and 2002, were not modified in connection with the proposed merger with FPL Group, and have been filed with the SEC and provided to the Public Service Commission.

For each of the approximately 250 participants in these plans, the change in control would result in the

• vesting of options, restricted stock, restricted stock units and performance units that are not already vested

• the cancellation and pay-out of the existing cash value of options (then-current stock price less exercise price for options), if required by the plan

• pro-rata payout of three-year performance units as of the date of completion of the merger, assuming maximum performance, with no payment for the period after the completion of the merger and the loss of any value associated with the time period after completion of the merger

It is important to note that these awards were granted as a component of prior years’ compensation, are performance based and would be earned out over time absent the merger. The payout required by the plans is intended to only deliver to the participant the embedded existing gain on such award (e.g., for stock options, it is simply the gain on the option between the stock price on the date the option was granted and the price of Constellation stock at the closing – an amount the participant had already earned through Company performance).

With respect to outstanding performance units, these were granted for two performance periods:

• 2004 LTIP: performance period of 2004 through 2006

• 2005 LTIP: performance period of 2005 through 2007

If the merger is completed as of December 31, 2006, the performance period for the 2004 LTIP will have been completed, and the only enhancement to the payout that would otherwise be made results from the plan’s requiring that the payout assume maximum performance; in fact, if the merger is completed after the payout date for the 2004 LTIP, scheduled for early 2007, there would be absolutely no enhancement of its payout. If the merger is completed earlier than December 31, 2006, the payment for the 2004 LTIP will also be less than the amounts set forth below because performance units are only paid out on a pro-rata basis during the performance period. Thus, by assuming December 31, 2006 as the closing date, we are showing the highest possible payment to the executive officers for the 2004 LTIP.

With respect to restricted stock units, it should be noted that these units are already vested, but are subject to a sale restriction until a designated period has lapsed, so the enhancement is only the cash payment for the restricted stock units prior to the lapse of the sale restriction – there is no enhancement in the amount of the actual payment.

In the following table, we have assumed that the merger with FPL Group is completed on December 31, 2006 and that the value of Constellation common stock is $52 per share at completion of the merger. The table sets forth the amount each executive officer would be expected to receive in cash with respect to stock options, restricted stock, restricted stock units and performance units.

Executive Officer	Cash for Vested Stock Options	Cash for Unvested Stock Options	2004 LTIP - Cash for 2004-2006 Performance Units	2005 LTIP - Cash for 2005-2007 Performance Units	Cash for Restricted Stock and Restricted Stock Units
	($’s in 000’s)	($’s in 000’s)	($’s in 000’s)	($’s in 000’s)	($’s in 000’s)
Allen, Paul	1,736	88	262	190	139
Brady, Thomas	3,066	260	800	466	347
Brooks, Thomas	1,204	496	1,500	1,000	2,360
Collins, John	1,767	107	312	266	139
Dawson, Felix	—	—	—	—	2,548
DeFontes, Kenneth	122	22	160	333	—
Perlman, Beth	690	22	400	333	—
Persky, George	—	—	—	—	2,548
Shattuck, Mayo	1,258	1,374	4,000	3,400	2,780
Smith, Follin	809	353	1,000	1,000	582
Ugol, Marc	972	107	312	266	139
Wallace, Michael	740	302	900	666	1,770
Yoskowitz, Irving	—	—	—	1,000	330

It should be noted that Mr. Shattuck has informed Constellation that he intends to direct Constellation to remit all of the after tax cash payments he would otherwise receive upon the closing of the proposed merger with FPL Group to a charitable foundation or other charitable organization.

As previously disclosed, executive officers whose options are actually cashed out and cancelled at closing will be entitled to replacement options, with an exercise price equal to the higher of the market price on the day of the completion of the merger or the original option price, and otherwise with the same terms as the cancelled options (as a result, such replacement options will not have immediate cash value at the closing of any merger). This is designed to exactly replace the terms and number of options that were cashed out and cancelled.

B. 2006 Long-term Incentive Awards

Each year, as part of their normal compensation package, approximately 150 Constellation employees typically receive an award of long-term incentive compensation that consists of a combination of stock options and performance units. These awards provide incentive to drive long-term performance and, through the potential increase in the value of Constellation stock, compensation upside to recipients.

For 2006, the Compensation Committee of Constellation’s Board of Directors (which consists entirely of directors who are “independent” under applicable New York Stock Exchange Listing Standards) concluded that, given the proposed merger with FPL Group, the grant of stock options and/or performance units was not appropriate and a program that was focused on retention of employees was required, and therefore no such awards were made in 2006. Instead, the Committee approved an award program, the existence of which was publicly disclosed by Constellation in a filing with the SEC, which provides for target awards that are payable in cash 25% upon closing of the merger with FPL Group and 75% one year later; however, if the merger is not completed by March 2007, the awards will be paid based upon meeting Constellation’s 2006 business plan.

As these awards are designed to provide recipients with an approximation of the value they would have been entitled to earn if the Company had awarded long-term incentive awards in the normal course of business, we do not view these awards as an enhancement of compensation related to the merger. In any event, assuming the merger is not completed by March 2007, payment of the awards will be based solely upon Constellation meeting its 2006 business plan regardless of the merger.

However, in the interests of full disclosure, the table below sets forth the amounts each executive officer would receive upon closing of the merger or, if the merger does not close, achievement of Constellation’s 2006 business plan, and the amount he or she would receive one year later:

Executive Officer	25% initial payment	75% payment one year later
	($’s in 000’s)	($’s in 000’s)
Allen, Paul	95	286
Brady, Thomas	234	703
Brooks, Thomas	750	2,250
Collins, John	100	300
Dawson, Felix	700	2,100
DeFontes, Kenneth	167	502
Perlman, Beth	167	502
Persky, George	706	2,118
Shattuck, Mayo	1,950	5,850
Smith, Follin	625	1,875
Ugol, Marc	131	393
Wallace, Michael	335	1,005
Yoskowitz, Irving	335	1,005

If the executive officer leaves voluntarily prior to either of the foregoing payments, he or she forfeits their right to such payment.

C. Severance Arrangements for Other than Executive Officers

Employees who are not a party to a change in control severance agreement are eligible to receive, in the event their employment is terminated without cause, a severance payment pursuant to plans which provide payments based on number of years of service, with a minimum payment of six months of base salary and bonus for management level employees. None of the executive officers who are parties to change in control severance agreements is eligible to participate in these severance arrangements.

III. EMPLOYMENT AGREEMENT WITH MAYO SHATTUCK

As previously publicly disclosed in SEC filings and to the Public Service Commission, Mr. Shattuck agreed, as part of the merger agreement with FPL Group, to enter into a three-year employment agreement to insure his continued employment with Constellation after the merger. As set forth in the employment agreement, Mr. Shattuck will serve as Chairman of the Board and have initial management responsibilities for Constellation’s competitive energy businesses. In connection with the employment agreement, Mr. Shattuck agreed to waive his right to receive any severance payments under his change in

control severance agreement in connection with the merger, even though he would have been entitled to such payments.

Under the terms of the employment agreement, which goes into effect only upon completion of the merger with FPL Group, Mr. Shattuck would have an aggregate base salary and bonus of not less than $5.0 million in 2007 and $2.5 million in each of 2008 and 2009. His aggregate base salary and bonus, and long-term incentive awards, would be as favorable as those provide to Constellation’s CEO after the merger is completed. In addition, he would be provided, at completion of the merger, with a grant of restricted stock units, subject to complete forfeiture if he terminates his employment prior to one year after closing unless such termination is without cause or for good reason. Assuming that the merger is completed on December 31, 2006, the value of the restricted stock units would be $13.5 million. The aggregate guaranteed minimum three-year compensation, including the value of the restricted stock units, is less than Mr. Shattuck has actually been paid for the past three years.

If Mr. Shattuck’s employment is terminated after completion of the merger, he would be entitled to continued health benefits, which Constellation estimates to be worth $46,000. Also, as noted above, in the event excise taxes under Section 4999 of the Internal Revenue Code are due, similar to many other companies, Constellation would pay an amount calculated so that the Mr. Shattuck is in the same position as if no such excise taxes were imposed over and above the normal income taxes which he must pay.

IV. PAYMENTS TO CONSTELLATION NON-EMPLOYEE DIRECTORS

The non-employee members of Constellation Energy’s board of directors will not receive any additional payments in connection with the proposed merger with FPL Group. However, certain directors have deferred all or a portion of retainer and meeting fees they have already earned. They would normally receive the fees within one year after ceasing to be a director, but will instead receive them within 30 days after a merger.

V. EFFECT OF ASSUMED MERGER CLOSING DATE

As noted earlier, the date which is assumed for the merger completion can significantly affect the calculation of the amounts set forth above. In this regard, if the merger is completed after March 2007, the 2004 LTIP discussed above will have been settled in accordance with its terms, and any payment will be unaffected by the merger. In addition, if the merger is not completed by March 2007, payment of the 2006 long-term incentive awards will be based solely upon Constellation meeting its 2006 business plan and such payments will be unaffected by the merger.

VI. NOTE CONCERNING PAYMENTS

None of the payments explained and detailed above will be charged or allocated to BGE or its ratepayers.

Commission File Number		Exact name of registrant as specified in its charter		IRS Employer Identification No.
1-12869		CONSTELLATION ENERGY GROUP, INC.		52-1964611

750 E. PRATT STREET, BALTIMORE, MARYLAND		21202
(Address of principal executive offices)		(Zip Code)

Exhibit No.		Description

99.1		Letter to President of the Senate and Speaker of the House of Delegates of the Maryland General Assembly

		CONSTELLATION ENERGY GROUP, INC.
		(Registrant)


Date:	June 1, 2006		/s/ Charles A. Berardesco
			Charles A. Berardesco
			Associate General Counsel, Chief Compliance Officer and Corporate Secretary

Exhibit No.		Description

99.1		Letter to President of the Senate and Speaker of the House of Delegates of the Maryland General Assembly



Mayo A. Shattuck III		K. W. Defontes, Jr.
Chairman, President and CEO		President
Constellation Energy		Baltimore Gas & Electric Company